System and method for a turbine combustor

ABSTRACT

A system includes a turbine combustor that includes a head end portion having a head end chamber, a combustion portion having a combustion chamber disposed downstream from the head end chamber, a cap disposed between the head end chamber and the combustion chamber, and a flow distributor configured to distribute an exhaust flow circumferentially around the head end chamber. The flow distributor includes at least one exhaust gas flow path.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and benefit of U.S. ProvisionalPatent Application No. 61/747,203, entitled “SYSTEM AND METHOD FOR ATURBINE COMBUSTOR,” filed on Dec. 28, 2012, which is hereby incorporatedby reference in its entirety for all purposes.

This application relates to U.S. Provisional Patent Application No.61/722,118, entitled “SYSTEM AND METHOD FOR DIFFUSION COMBUSTION IN ASTOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM,” filed onNov. 2, 2012, U.S. Provisional Patent Application No. 61/722,115,entitled “SYSTEM AND METHOD FOR DIFFUSION COMBUSTION WITH FUEL-DILUENTMIXING IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINESYSTEM,” filed on Nov. 2, 2012, U.S. Provisional Patent Application No.61/722,114, entitled “SYSTEM AND METHOD FOR DIFFUSION COMBUSTION WITHOXIDANT-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GASTURBINE SYSTEM,” filed on Nov. 2, 2012, and U.S. Provisional PatentApplication No. 61/722,111, entitled “SYSTEM AND METHOD FOR LOAD CONTROLWITH DIFFUSION COMBUSTION IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATIONGAS TURBINE SYSTEM,” filed on Nov. 2, 2012, all of which are hereinincorporated by reference in their entirety for all purposes.

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to gas turbine engines, and,more particularly, to systems and methods for turbine combustors of gasturbine engines.

Gas turbine engines are used in a wide variety of applications, such aspower generation, aircraft, and various machinery. Gas turbine enginesgenerally combust a fuel with an oxidant (e.g., air) in a combustorsection to generate hot combustion products, which then drive one ormore turbine stages of a turbine section. In turn, the turbine sectiondrives one or more compressor stages of a compressor section, therebycompressing oxidant for intake into the combustor section along with thefuel. Again, the fuel and oxidant mix in the combustor section, and thencombust to produce the hot combustion products. Gas turbine enginesgenerally premix the fuel and oxidant along one or more flow pathsupstream from a combustion chamber of the combustor section.Unfortunately, certain components of the combustor section are exposedto high temperatures, which may reduce the life of the components.Furthermore, gas turbine engines typically consume a vast amount of airas the oxidant, and output a considerable amount of exhaust gas into theatmosphere. In other words, the exhaust gas is typically wasted as abyproduct of the gas turbine operation.

BRIEF DESCRIPTION OF THE INVENTION

Certain embodiments commensurate in scope with the originally claimedinvention are summarized below. These embodiments are not intended tolimit the scope of the claimed invention, but rather these embodimentsare intended only to provide a brief summary of possible forms of theinvention. Indeed, the invention may encompass a variety of forms thatmay be similar to or different from the embodiments set forth below.

In a first embodiment, a system includes a turbine combustor thatincludes a head end portion having a head end chamber, a combustionportion having a combustion chamber disposed downstream from the headend chamber, a cap disposed between the head end chamber and thecombustion chamber, and a flow distributor configured to distribute anexhaust flow circumferentially around the head end chamber. The flowdistributor includes at least one exhaust gas flow path.

In a second embodiment, a system includes an oxidant compressor and agas turbine engine that includes a combustor section having a turbinecombustor, a turbine driven by combustion products from the turbinecombustor, and an exhaust gas compressor driven by the turbine. Theexhaust gas compressor is configured to compress and route an exhaustflow to the turbine combustor and the oxidant compressor is configuredto compress and route an oxidant flow to the turbine combustor. The gasturbine engine also includes an exhaust extraction port coupled to thecombustor section and a flow distributor configured to distribute anexhaust flow circumferentially around a head end chamber of the turbinecombustor. The flow distributor includes at least one exhaust gas flowpath.

In a third embodiment, a method includes extracting a first exhaust flowof an exhaust gas at a combustion section of a gas turbine engine,routing a second exhaust flow of the exhaust gas toward an end plate ofa head end portion of a turbine combustor in the combustion section, androuting a third exhaust flow of the exhaust gas toward a cap of the headend portion. The cap is disposed between a head end region and acombustion region. The method also includes routing an oxidant flow intothe head end portion and distributing at least one of the first exhaustflow, the second exhaust flow, or the third exhaust flowcircumferentially around the head end portion using a flow distributor.The flow distributor includes at least one exhaust gas flow path.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a diagram of an embodiment of a system having a turbine-basedservice system coupled to a hydrocarbon production system;

FIG. 2 is a diagram of an embodiment of the system of FIG. 1, furtherillustrating a control system and a combined cycle system;

FIG. 3 is a diagram of an embodiment of the system of FIGS. 1 and 2,further illustrating details of a gas turbine engine, exhaust gas supplysystem, and exhaust gas processing system;

FIG. 4 is a flow chart of an embodiment of a process for operating thesystem of FIGS. 1-3;

FIG. 5 is a flow chart of an embodiment of a process for operating a gasturbine engine with exhaust gas recirculation;

FIG. 6 is a schematic diagram of an embodiment of a combustor section ofa gas turbine engine with exhaust gas recirculation;

FIG. 7 is a schematic diagram of an embodiment of a turbine combustor ofthe gas turbine engine of FIG. 6, illustrating a flow distributor;

FIG. 8 is a radial cross-sectional view of an embodiment of a turbinecombustor taken along line 8-8 of FIG. 7;

FIG. 9 is a radial cross-sectional view of an embodiment of a turbinecombustor taken along line 8-8 of FIG. 7;

FIG. 10 is a cross-sectional view of an embodiment of a turbinecombustor of the gas turbine engine of FIG. 6, illustrating a flowdistributor coupled to an oxidant intake port;

FIG. 11 is a cross-sectional view of an embodiment of a turbinecombustor of the gas turbine engine of FIG. 6, illustrating a flowdistributor coupled to an exhaust extraction port;

FIG. 12 is a schematic diagram of an embodiment of a turbine combustorof the gas turbine engine of FIG. 6, illustrating a flow distributor;

FIG. 13 is a radial cross-sectional view of an embodiment of a turbinecombustor taken along line 13-13 of FIG. 12;

FIG. 14 is a radial cross-sectional view of an embodiment of a turbinecombustor taken along line 13-13 of FIG. 12;

FIG. 15 is a cross-sectional view of an embodiment of a turbinecombustor of the gas turbine engine of FIG. 6, illustrating a flowdistributor coupled to an exhaust gas flow path;

FIG. 16 is a cross-sectional view of an embodiment of a turbinecombustor of the gas turbine engine of FIG. 6, illustrating a flowdistributor coupled to an exhaust extraction port;

FIG. 17 is an exploded schematic of various embodiments of flowdistributors that may be removably coupled to the turbine combustor;

FIG. 18 is a radial cross-sectional view of an embodiment of a turbinecombustor with a plurality of flow distributors;

FIG. 19 is a radial cross-sectional view of an embodiment of a turbinecombustor with a plurality of passages; and

FIG. 20 is a radial cross-sectional view of an embodiment of a turbinecombustor with a plurality of passages of different diameters.

DETAILED DESCRIPTION OF THE INVENTION

One or more specific embodiments of the present invention will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in any engineering ordesign project, numerous implementation-specific decisions must be madeto achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucha development effort might be complex and time consuming, but wouldnevertheless be a routine undertaking of design, fabrication, andmanufacture for those of ordinary skill having the benefit of thisdisclosure.

When introducing elements of various embodiments of the presentinvention, the articles “a,” “an,” “the,” and “said” are intended tomean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.

As discussed in detail below, the disclosed embodiments relate generallyto gas turbine systems with exhaust gas recirculation (EGR), andparticularly stoichiometric operation of the gas turbine systems usingEGR. For example, the gas turbine systems may be configured torecirculate the exhaust gas along an exhaust recirculation path,stoichiometrically combust fuel and oxidant along with at least some ofthe recirculated exhaust gas, and capture the exhaust gas for use invarious target systems. The recirculation of the exhaust gas along withstoichiometric combustion may help to increase the concentration levelof carbon dioxide (CO₂) in the exhaust gas, which can then be posttreated to separate and purify the CO₂ and nitrogen (N₂) for use invarious target systems. The gas turbine systems also may employ variousexhaust gas processing (e.g., heat recovery, catalyst reactions, etc.)along the exhaust recirculation path, thereby increasing theconcentration level of CO₂, reducing concentration levels of otheremissions (e.g., carbon monoxide, nitrogen oxides, and unburnthydrocarbons), and increasing energy recovery (e.g., with heat recoveryunits). Furthermore, the gas turbine engines may be configured tocombust the fuel and oxidant with one or more diffusion flames (e.g.,using diffusion fuel nozzles), premix flames (e.g., using premix fuelnozzles), or any combination thereof. In certain embodiments, thediffusion flames may help to maintain stability and operation withincertain limits for stoichiometric combustion, which in turn helps toincrease production of CO₂. For example, a gas turbine system operatingwith diffusion flames may enable a greater quantity of EGR, as comparedto a gas turbine system operating with premix flames. In turn, theincreased quantity of EGR helps to increase CO₂ production. Possibletarget systems include pipelines, storage tanks, carbon sequestrationsystems, and hydrocarbon production systems, such as enhanced oilrecovery (EOR) systems.

The disclosed embodiments provide systems and methods for turbinecombustors of gas turbine systems with EGR. Specifically, the turbinecombustor may include a head end portion having a head end chamber, acombustion portion having a combustion chamber disposed downstream fromthe head end chamber, a cap disposed between the head end chamber andthe combustion chamber, and a flow distributor configured to distributean exhaust flow circumferentially around the head end chamber. The flowdistributor may include at least one exhaust gas flow path. In addition,the flow distributor may direct the exhaust flow into the head endchamber or to an exhaust gas extraction system and/or a hydrocarbonproduction system. In addition, the turbine combustor may include amixing region to mix the exhaust flow with the oxidant flow to providethe oxidant-exhaust mixture, which may be directed into the head endchamber by the flow distributor. The turbine combustor may combust theoxidant-exhaust mixture together with a fuel to generate combustionproducts or gases that may be used to drive a turbine. In certainembodiments, the turbine combustor may be part of a stoichiometericexhaust gas recirculation (SEGR) gas turbine engine. The SEGR gasturbine engine may include a combustor section having the turbinecombustor, a turbine driven by the combustion products from the turbinecombustor, and an exhaust gas compressor driven by the turbine. Theexhaust gas compressor may compress and route an exhaust flow to theturbine combustor and an oxidant compressor may compress and route theoxidant flow to the turbine combustor. In addition, an exhaustextraction port may be coupled to the combustor section. Use of suchembodiments of turbine combustors may provide several advantagescompared to previous turbine combustors. For example, the disclosedembodiments of turbine combustors may directly provide the exhaust flowused in other applications, such as the hydrocarbon production system.In addition, such turbine combustors may provide improved cooling ofinternal components of the turbine combustor. Specifically, even thoughlarge amounts of the exhaust flow are removed from the turbinecombustor, the internal configuration of the turbine combustor enablesinternal surfaces of the combustor that are exposed to high temperaturesto be cooled by the exhaust flow. For example, the exhaust flow may becircumferentially distributed by the flow distributor to certainportions of the turbine combustor for increased cooling. Thus, suchturbine combustors may have increased longevity and/or reducedmaintenance costs compared to previous combustors.

FIG. 1 is a diagram of an embodiment of a system 10 having anhydrocarbon production system 12 associated with a turbine-based servicesystem 14. As discussed in further detail below, various embodiments ofthe turbine-based service system 14 are configured to provide variousservices, such as electrical power, mechanical power, and fluids (e.g.,exhaust gas), to the hydrocarbon production system 12 to facilitate theproduction or retrieval of oil and/or gas. In the illustratedembodiment, the hydrocarbon production system 12 includes an oil/gasextraction system 16 and an enhanced oil recovery (EOR) system 18, whichare coupled to a subterranean reservoir 20 (e.g., an oil, gas, orhydrocarbon reservoir). The oil/gas extraction system 16 includes avariety of surface equipment 22, such as a Christmas tree or productiontree 24, coupled to an oil/gas well 26. Furthermore, the well 26 mayinclude one or more tubulars 28 extending through a drilled bore 30 inthe earth 32 to the subterranean reservoir 20. The tree 24 includes oneor more valves, chokes, isolation sleeves, blowout preventers, andvarious flow control devices, which regulate pressures and control flowsto and from the subterranean reservoir 20. While the tree 24 isgenerally used to control the flow of the production fluid (e.g., oil orgas) out of the subterranean reservoir 20, the EOR system 18 mayincrease the production of oil or gas by injecting one or more fluidsinto the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34,which has one or more tubulars 36 extending through a bore 38 in theearth 32 to the subterranean reservoir 20. For example, the EOR system18 may route one or more fluids 40, such as gas, steam, water,chemicals, or any combination thereof, into the fluid injection system34. For example, as discussed in further detail below, the EOR system 18may be coupled to the turbine-based service system 14, such that thesystem 14 routes an exhaust gas 42 (e.g., substantially or entirely freeof oxygen) to the EOR system 18 for use as the injection fluid 40. Thefluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42)through the one or more tubulars 36 into the subterranean reservoir 20,as indicated by arrows 44. The injection fluid 40 enters thesubterranean reservoir 20 through the tubular 36 at an offset distance46 away from the tubular 28 of the oil/gas well 26. Accordingly, theinjection fluid 40 displaces the oil/gas 48 disposed in the subterraneanreservoir 20, and drives the oil/gas 48 up through the one or moretubulars 28 of the hydrocarbon production system 12, as indicated byarrows 50. As discussed in further detail below, the injection fluid 40may include the exhaust gas 42 originating from the turbine-basedservice system 14, which is able to generate the exhaust gas 42 on-siteas needed by the hydrocarbon production system 12. In other words, theturbine-based system 14 may simultaneously generate one or more services(e.g., electrical power, mechanical power, steam, water (e.g.,desalinated water), and exhaust gas (e.g., substantially free ofoxygen)) for use by the hydrocarbon production system 12, therebyreducing or eliminating the reliance on external sources of suchservices.

In the illustrated embodiment, the turbine-based service system 14includes a stoichiometric exhaust gas recirculation (SEGR) gas turbinesystem 52 and an exhaust gas (EG) processing system 54. The gas turbinesystem 52 may be configured to operate in a stoichiometric combustionmode of operation (e.g., a stoichiometric control mode) and anon-stoichiometric combustion mode of operation (e.g., anon-stoichiometric control mode), such as a fuel-lean control mode or afuel-rich control mode. In the stoichiometric control mode, thecombustion generally occurs in a substantially stoichiometric ratio of afuel and oxidant, thereby resulting in substantially stoichiometriccombustion. In particular, stoichiometric combustion generally involvesconsuming substantially all of the fuel and oxidant in the combustionreaction, such that the products of combustion are substantially orentirely free of unburnt fuel and oxidant. One measure of stoichiometriccombustion is the equivalence ratio, or phi (Φ), which is the ratio ofthe actual fuel/oxidant ratio relative to the stoichiometricfuel/oxidant ratio. An equivalence ratio of greater than 1.0 results ina fuel-rich combustion of the fuel and oxidant, whereas an equivalenceratio of less than 1.0 results in a fuel-lean combustion of the fuel andoxidant. In contrast, an equivalence ratio of 1.0 results in combustionthat is neither fuel-rich nor fuel-lean, thereby substantially consumingall of the fuel and oxidant in the combustion reaction. In context ofthe disclosed embodiments, the term stoichiometric or substantiallystoichiometric may refer to an equivalence ratio of approximately 0.95to approximately 1.05. However, the disclosed embodiments may alsoinclude an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03,0.04, 0.05, or more. Again, the stoichiometric combustion of fuel andoxidant in the turbine-based service system 14 may result in products ofcombustion or exhaust gas (e.g., 42) with substantially no unburnt fuelor oxidant remaining. For example, the exhaust gas 42 may have less than1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburntfuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. By further example, the exhaust gas42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90,100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts permillion by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel orhydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. However, the disclosed embodimentsalso may produce other ranges of residual fuel, oxidant, and otheremissions levels in the exhaust gas 42. As used herein, the termsemissions, emissions levels, and emissions targets may refer toconcentration levels of certain products of combustion (e.g., NO_(X),CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculatedgas streams, vented gas streams (e.g., exhausted into the atmosphere),and gas streams used in various target systems (e.g., the hydrocarbonproduction system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54may include a variety of components in different embodiments, theillustrated EG processing system 54 includes a heat recovery steamgenerator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58,which receive and process an exhaust gas 60 originating from the SEGRgas turbine system 52. The HRSG 56 may include one or more heatexchangers, condensers, and various heat recovery equipment, whichcollectively function to transfer heat from the exhaust gas 60 to astream of water, thereby generating steam 62. The steam 62 may be usedin one or more steam turbines, the EOR system 18, or any other portionof the hydrocarbon production system 12. For example, the HRSG 56 maygenerate low pressure, medium pressure, and/or high pressure steam 62,which may be selectively applied to low, medium, and high pressure steamturbine stages, or different applications of the EOR system 18. Inaddition to the steam 62, a treated water 64, such as a desalinatedwater, may be generated by the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 or the SEGR gas turbinesystem 52. The treated water 64 (e.g., desalinated water) may beparticularly useful in areas with water shortages, such as inland ordesert regions. The treated water 64 may be generated, at least in part,due to the large volume of air driving combustion of fuel within theSEGR gas turbine system 52. While the on-site generation of steam 62 andwater 64 may be beneficial in many applications (including thehydrocarbon production system 12), the on-site generation of exhaust gas42, 60 may be particularly beneficial for the EOR system 18, due to itslow oxygen content, high pressure, and heat derived from the SEGR gasturbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 may output or recirculatean exhaust gas 66 into the SEGR gas turbine system 52, while alsorouting the exhaust gas 42 to the EOR system 18 for use with thehydrocarbon production system 12. Likewise, the exhaust gas 42 may beextracted directly from the SEGR gas turbine system 52 (i.e., withoutpassing through the EG processing system 54) for use in the EOR system18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EGprocessing system 54. For example, the EGR system 58 includes one ormore conduits, valves, blowers, exhaust gas treatment systems (e.g.,filters, particulate removal units, gas separation units, gaspurification units, heat exchangers, heat recovery units, moistureremoval units, catalyst units, chemical injection units, or anycombination thereof), and controls to recirculate the exhaust gas alongan exhaust gas circulation path from an output (e.g., discharged exhaustgas 60) to an input (e.g., intake exhaust gas 66) of the SEGR gasturbine system 52. In the illustrated embodiment, the SEGR gas turbinesystem 52 intakes the exhaust gas 66 into a compressor section havingone or more compressors, thereby compressing the exhaust gas 66 for usein a combustor section along with an intake of an oxidant 68 and one ormore fuels 70. The oxidant 68 may include ambient air, pure oxygen,oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, orany suitable oxidant that facilitates combustion of the fuel 70. Thefuel 70 may include one or more gas fuels, liquid fuels, or anycombination thereof. For example, the fuel 70 may include natural gas,liquefied natural gas (LNG), syngas, methane, ethane, propane, butane,naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or anycombination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66,the oxidant 68, and the fuel 70 in the combustor section, therebygenerating hot combustion gases or exhaust gas 60 to drive one or moreturbine stages in a turbine section. In certain embodiments, eachcombustor in the combustor section includes one or more premix fuelnozzles, one or more diffusion fuel nozzles, or any combination thereof.For example, each premix fuel nozzle may be configured to mix theoxidant 68 and the fuel 70 internally within the fuel nozzle and/orpartially upstream of the fuel nozzle, thereby injecting an oxidant-fuelmixture from the fuel nozzle into the combustion zone for a premixedcombustion (e.g., a premixed flame). By further example, each diffusionfuel nozzle may be configured to isolate the flows of oxidant 68 andfuel 70 within the fuel nozzle, thereby separately injecting the oxidant68 and the fuel 70 from the fuel nozzle into the combustion zone fordiffusion combustion (e.g., a diffusion flame). In particular, thediffusion combustion provided by the diffusion fuel nozzles delaysmixing of the oxidant 68 and the fuel 70 until the point of initialcombustion, i.e., the flame region. In embodiments employing thediffusion fuel nozzles, the diffusion flame may provide increased flamestability, because the diffusion flame generally forms at the point ofstoichiometry between the separate streams of oxidant 68 and fuel 70(i.e., as the oxidant 68 and fuel 70 are mixing). In certainembodiments, one or more diluents (e.g., the exhaust gas 60, steam,nitrogen, or another inert gas) may be pre-mixed with the oxidant 68,the fuel 70, or both, in either the diffusion fuel nozzle or the premixfuel nozzle. In addition, one or more diluents (e.g., the exhaust gas60, steam, nitrogen, or another inert gas) may be injected into thecombustor at or downstream from the point of combustion within eachcombustor. The use of these diluents may help temper the flame (e.g.,premix flame or diffusion flame), thereby helping to reduce NO_(X)emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂).Regardless of the type of flame, the combustion produces hot combustiongases or exhaust gas 60 to drive one or more turbine stages. As eachturbine stage is driven by the exhaust gas 60, the SEGR gas turbinesystem 52 generates a mechanical power 72 and/or an electrical power 74(e.g., via an electrical generator). The system 52 also outputs theexhaust gas 60, and may further output water 64. Again, the water 64 maybe a treated water, such as a desalinated water, which may be useful ina variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52using one or more extraction points 76. For example, the illustratedembodiment includes an exhaust gas (EG) supply system 78 having anexhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatmentsystem 82, which receive exhaust gas 42 from the extraction points 76,treat the exhaust gas 42, and then supply or distribute the exhaust gas42 to various target systems. The target systems may include the EORsystem 18 and/or other systems, such as a pipeline 86, a storage tank88, or a carbon sequestration system 90. The EG extraction system 80 mayinclude one or more conduits, valves, controls, and flow separations,which facilitate isolation of the exhaust gas 42 from the oxidant 68,the fuel 70, and other contaminants, while also controlling thetemperature, pressure, and flow rate of the extracted exhaust gas 42.The EG treatment system 82 may include one or more heat exchangers(e.g., heat recovery units such as heat recovery steam generators,condensers, coolers, or heaters), catalyst systems (e.g., oxidationcatalyst systems), particulate and/or water removal systems (e.g., gasdehydration units, inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, exhaust gascompressors, any combination thereof. These subsystems of the EGtreatment system 82 enable control of the temperature, pressure, flowrate, moisture content (e.g., amount of water removal), particulatecontent (e.g., amount of particulate removal), and gas composition(e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of theEG treatment system 82, depending on the target system. For example, theEG treatment system 82 may direct all or part of the exhaust gas 42through a carbon capture system, a gas separation system, a gaspurification system, and/or a solvent based treatment system, which iscontrolled to separate and purify a carbonaceous gas (e.g., carbondioxide) 92 and/or nitrogen (N₂) 94 for use in the various targetsystems. For example, embodiments of the EG treatment system 82 mayperform gas separation and purification to produce a plurality ofdifferent streams 95 of exhaust gas 42, such as a first stream 96, asecond stream 97, and a third stream 98. The first stream 96 may have afirst composition that is rich in carbon dioxide and/or lean in nitrogen(e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have asecond composition that has intermediate concentration levels of carbondioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂stream). The third stream 98 may have a third composition that is leanin carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ richstream). Each stream 95 (e.g., 96, 97, and 98) may include a gasdehydration unit, a filter, a gas compressor, or any combinationthereof, to facilitate delivery of the stream 95 to a target system. Incertain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂purity or concentration level of greater than approximately 70, 75, 80,85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity orconcentration level of less than approximately 1, 2, 3, 4, 5, 10, 15,20, 25, or percent by volume. In contrast, the CO₂ lean, N₂ rich stream98 may have a CO₂ purity or concentration level of less thanapproximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or percent by volume, and aN₂ purity or concentration level of greater than approximately 70, 75,80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. The intermediateconcentration CO₂, N₂ stream 97 may have a CO₂ purity or concentrationlevel and/or a N₂ purity or concentration level of between approximately30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent by volume. Althoughthe foregoing ranges are merely non-limiting examples, the CO₂ rich, N₂lean stream 96 and the CO₂ lean, N₂ rich stream 98 may be particularlywell suited for use with the EOR system 18 and the other systems 84.However, any of these rich, lean, or intermediate concentration CO₂streams 95 may be used, alone or in various combinations, with the EORsystem 18 and the other systems 84. For example, the EOR system 18 andthe other systems 84 (e.g., the pipeline 86, storage tank 88, and thecarbon sequestration system 90) each may receive one or more CO₂ rich,N₂ lean streams 96, one or more CO₂ lean, N₂ rich streams 98, one ormore intermediate concentration CO₂, N₂ streams 97, and one or moreuntreated exhaust gas 42 streams (i.e., bypassing the EG treatmentsystem 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or moreextraction points 76 along the compressor section, the combustorsection, and/or the turbine section, such that the exhaust gas 42 may beused in the EOR system 18 and other systems 84 at suitable temperaturesand pressures. The EG extraction system 80 and/or the EG treatmentsystem 82 also may circulate fluid flows (e.g., exhaust gas 42) to andfrom the EG processing system 54. For example, a portion of the exhaustgas 42 passing through the EG processing system 54 may be extracted bythe EG extraction system 80 for use in the EOR system 18 and the othersystems 84. In certain embodiments, the EG supply system 78 and the EGprocessing system 54 may be independent or integral with one another,and thus may use independent or common subsystems. For example, the EGtreatment system 82 may be used by both the EG supply system 78 and theEG processing system 54. Exhaust gas 42 extracted from the EG processingsystem 54 may undergo multiple stages of gas treatment, such as one ormore stages of gas treatment in the EG processing system 54 followed byone or more additional stages of gas treatment in the EG treatmentsystem 82.

At each extraction point 76, the extracted exhaust gas 42 may besubstantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel orhydrocarbons) due to substantially stoichiometric combustion and/or gastreatment in the EG processing system 54. Furthermore, depending on thetarget system, the extracted exhaust gas 42 may undergo furthertreatment in the EG treatment system 82 of the EG supply system 78,thereby further reducing any residual oxidant 68, fuel 70, or otherundesirable products of combustion. For example, either before or aftertreatment in the EG treatment system 82, the extracted exhaust gas 42may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. By furtherexample, either before or after treatment in the EG treatment system 82,the extracted exhaust gas 42 may have less than approximately 10, 20,30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000,4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. Thus, the exhaustgas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables theexhaust extraction at a multitude of locations 76. For example, thecompressor section of the system 52 may be used to compress the exhaustgas 66 without any oxidant 68 (i.e., only compression of the exhaust gas66), such that a substantially oxygen-free exhaust gas 42 may beextracted from the compressor section and/or the combustor section priorto entry of the oxidant 68 and the fuel 70. The extraction points 76 maybe located at interstage ports between adjacent compressor stages, atports along the compressor discharge casing, at ports along eachcombustor in the combustor section, or any combination thereof. Incertain embodiments, the exhaust gas 66 may not mix with the oxidant 68and fuel 70 until it reaches the head end portion and/or fuel nozzles ofeach combustor in the combustor section. Furthermore, one or more flowseparators (e.g., walls, dividers, baffles, or the like) may be used toisolate the oxidant 68 and the fuel 70 from the extraction points 76.With these flow separators, the extraction points 76 may be disposeddirectly along a wall of each combustor in the combustor section.

Once the exhaust gas 66, oxidant 68, and fuel 70 flow through the headend portion (e.g., through fuel nozzles) into the combustion portion(e.g., combustion chamber) of each combustor, the SEGR gas turbinesystem 52 is controlled to provide a substantially stoichiometriccombustion of the exhaust gas 66, oxidant 68, and fuel 70. For example,the system 52 may maintain an equivalence ratio of approximately 0.95 toapproximately 1.05. As a result, the products of combustion of themixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor issubstantially free of oxygen and unburnt fuel. Thus, the products ofcombustion (or exhaust gas) may be extracted from the turbine section ofthe SEGR gas turbine system 52 for use as the exhaust gas 42 routed tothe EOR system 18. Along the turbine section, the extraction points 76may be located at any turbine stage, such as interstage ports betweenadjacent turbine stages. Thus, using any of the foregoing extractionpoints 76, the turbine-based service system 14 may generate, extract,and deliver the exhaust gas 42 to the hydrocarbon production system 12(e.g., the EOR system 18) for use in the production of oil/gas 48 fromthe subterranean reservoir 20.

FIG. 2 is a diagram of an embodiment of the system 10 of FIG. 1,illustrating a control system 100 coupled to the turbine-based servicesystem 14 and the hydrocarbon production system 12. In the illustratedembodiment, the turbine-based service system 14 includes a combinedcycle system 102, which includes the SEGR gas turbine system 52 as atopping cycle, a steam turbine 104 as a bottoming cycle, and the HRSG 56to recover heat from the exhaust gas 60 to generate the steam 62 fordriving the steam turbine 104. Again, the SEGR gas turbine system 52receives, mixes, and stoichiometrically combusts the exhaust gas 66, theoxidant 68, and the fuel 70 (e.g., premix and/or diffusion flames),thereby producing the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64. For example, the SEGR gasturbine system 52 may drive one or more loads or machinery 106, such asan electrical generator, an oxidant compressor (e.g., a main aircompressor), a gear box, a pump, equipment of the hydrocarbon productionsystem 12, or any combination thereof. In some embodiments, themachinery 106 may include other drives, such as electrical motors orsteam turbines (e.g., the steam turbine 104), in tandem with the SEGRgas turbine system 52. Accordingly, an output of the machinery 106driven by the SEGR gas turbines system 52 (and any additional drives)may include the mechanical power 72 and the electrical power 74. Themechanical power 72 and/or the electrical power 74 may be used on-sitefor powering the hydrocarbon production system 12, the electrical power74 may be distributed to the power grid, or any combination thereof. Theoutput of the machinery 106 also may include a compressed fluid, such asa compressed oxidant 68 (e.g., air or oxygen), for intake into thecombustion section of the SEGR gas turbine system 52. Each of theseoutputs (e.g., the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64) may be considered a service ofthe turbine-based service system 14.

The SEGR gas turbine system 52 produces the exhaust gas 42, 60, whichmay be substantially free of oxygen, and routes this exhaust gas 42, 60to the EG processing system 54 and/or the EG supply system 78. The EGsupply system 78 may treat and delivery the exhaust gas 42 (e.g.,streams 95) to the hydrocarbon production system 12 and/or the othersystems 84. As discussed above, the EG processing system 54 may includethe HRSG 56 and the EGR system 58. The HRSG 56 may include one or moreheat exchangers, condensers, and various heat recovery equipment, whichmay be used to recover or transfer heat from the exhaust gas 60 to water108 to generate the steam 62 for driving the steam turbine 104. Similarto the SEGR gas turbine system 52, the steam turbine 104 may drive oneor more loads or machinery 106, thereby generating the mechanical power72 and the electrical power 74. In the illustrated embodiment, the SEGRgas turbine system 52 and the steam turbine 104 are arranged in tandemto drive the same machinery 106. However, in other embodiments, the SEGRgas turbine system 52 and the steam turbine 104 may separately drivedifferent machinery 106 to independently generate mechanical power 72and/or electrical power 74. As the steam turbine 104 is driven by thesteam 62 from the HRSG 56, the steam 62 gradually decreases intemperature and pressure. Accordingly, the steam turbine 104recirculates the used steam 62 and/or water 108 back into the HRSG 56for additional steam generation via heat recovery from the exhaust gas60. In addition to steam generation, the HRSG 56, the EGR system 58,and/or another portion of the EG processing system 54 may produce thewater 64, the exhaust gas 42 for use with the hydrocarbon productionsystem 12, and the exhaust gas 66 for use as an input into the SEGR gasturbine system 52. For example, the water 64 may be a treated water 64,such as a desalinated water for use in other applications. Thedesalinated water may be particularly useful in regions of low wateravailability. Regarding the exhaust gas 60, embodiments of the EGprocessing system 54 may be configured to recirculate the exhaust gas 60through the EGR system 58 with or without passing the exhaust gas 60through the HRSG 56.

In the illustrated embodiment, the SEGR gas turbine system 52 has anexhaust recirculation path 110, which extends from an exhaust outlet toan exhaust inlet of the system 52. Along the path 110, the exhaust gas60 passes through the EG processing system 54, which includes the HRSG56 and the EGR system 58 in the illustrated embodiment. The EGR system58 may include one or more conduits, valves, blowers, gas treatmentsystems (e.g., filters, particulate removal units, gas separation units,gas purification units, heat exchangers, heat recovery units such asheat recovery steam generators, moisture removal units, catalyst units,chemical injection units, or any combination thereof) in series and/orparallel arrangements along the path 110. In other words, the EGR system58 may include any flow control components, pressure control components,temperature control components, moisture control components, and gascomposition control components along the exhaust recirculation path 110between the exhaust outlet and the exhaust inlet of the system 52.Accordingly, in embodiments with the HRSG 56 along the path 110, theHRSG 56 may be considered a component of the EGR system 58. However, incertain embodiments, the HRSG 56 may be disposed along an exhaust pathindependent from the exhaust recirculation path 110. Regardless ofwhether the HRSG 56 is along a separate path or a common path with theEGR system 58, the HRSG 56 and the EGR system 58 intake the exhaust gas60 and output either the recirculated exhaust gas 66, the exhaust gas 42for use with the EG supply system 78 (e.g., for the hydrocarbonproduction system 12 and/or other systems 84), or another output ofexhaust gas. Again, the SEGR gas turbine system 52 intakes, mixes, andstoichiometrically combusts the exhaust gas 66, the oxidant 68, and thefuel 70 (e.g., premixed and/or diffusion flames) to produce asubstantially oxygen-free and fuel-free exhaust gas 60 for distributionto the EG processing system 54, the hydrocarbon production system 12, orother systems 84.

As noted above with reference to FIG. 1, the hydrocarbon productionsystem 12 may include a variety of equipment to facilitate the recoveryor production of oil/gas 48 from a subterranean reservoir 20 through anoil/gas well 26. For example, the hydrocarbon production system 12 mayinclude the EOR system 18 having the fluid injection system 34. In theillustrated embodiment, the fluid injection system 34 includes anexhaust gas injection EOR system 112 and a steam injection EOR system114. Although the fluid injection system 34 may receive fluids from avariety of sources, the illustrated embodiment may receive the exhaustgas 42 and the steam 62 from the turbine-based service system 14. Theexhaust gas 42 and/or the steam 62 produced by the turbine-based servicesystem 14 also may be routed to the hydrocarbon production system 12 foruse in other oil/gas systems 116.

The quantity, quality, and flow of the exhaust gas 42 and/or the steam62 may be controlled by the control system 100. The control system 100may be dedicated entirely to the turbine-based service system 14, or thecontrol system 100 may optionally also provide control (or at least somedata to facilitate control) for the hydrocarbon production system 12and/or other systems 84. In the illustrated embodiment, the controlsystem 100 includes a controller 118 having a processor 120, a memory122, a steam turbine control 124, a SEGR gas turbine system control 126,and a machinery control 128. The processor 120 may include a singleprocessor or two or more redundant processors, such as triple redundantprocessors for control of the turbine-based service system 14. Thememory 122 may include volatile and/or non-volatile memory. For example,the memory 122 may include one or more hard drives, flash memory,read-only memory, random access memory, or any combination thereof. Thecontrols 124, 126, and 128 may include software and/or hardwarecontrols. For example, the controls 124, 126, and 128 may includevarious instructions or code stored on the memory 122 and executable bythe processor 120. The control 124 is configured to control operation ofthe steam turbine 104, the SEGR gas turbine system control 126 isconfigured to control the system 52, and the machinery control 128 isconfigured to control the machinery 106. Thus, the controller 118 (e.g.,controls 124, 126, and 128) may be configured to coordinate varioussub-systems of the turbine-based service system 14 to provide a suitablestream of the exhaust gas 42 to the hydrocarbon production system 12.

In certain embodiments of the control system 100, each element (e.g.,system, subsystem, and component) illustrated in the drawings ordescribed herein includes (e.g., directly within, upstream, ordownstream of such element) one or more industrial control features,such as sensors and control devices, which are communicatively coupledwith one another over an industrial control network along with thecontroller 118. For example, the control devices associated with eachelement may include a dedicated device controller (e.g., including aprocessor, memory, and control instructions), one or more actuators,valves, switches, and industrial control equipment, which enable controlbased on sensor feedback 130, control signals from the controller 118,control signals from a user, or any combination thereof. Thus, any ofthe control functionality described herein may be implemented withcontrol instructions stored and/or executable by the controller 118,dedicated device controllers associated with each element, or acombination thereof.

In order to facilitate such control functionality, the control system100 includes one or more sensors distributed throughout the system 10 toobtain the sensor feedback 130 for use in execution of the variouscontrols, e.g., the controls 124, 126, and 128. For example, the sensorfeedback 130 may be obtained from sensors distributed throughout theSEGR gas turbine system 52, the machinery 106, the EG processing system54, the steam turbine 104, the hydrocarbon production system 12, or anyother components throughout the turbine-based service system 14 or thehydrocarbon production system 12. For example, the sensor feedback 130may include temperature feedback, pressure feedback, flow rate feedback,flame temperature feedback, combustion dynamics feedback, intake oxidantcomposition feedback, intake fuel composition feedback, exhaustcomposition feedback, the output level of mechanical power 72, theoutput level of electrical power 74, the output quantity of the exhaustgas 42, 60, the output quantity or quality of the water 64, or anycombination thereof. For example, the sensor feedback 130 may include acomposition of the exhaust gas 42, 60 to facilitate stoichiometriccombustion in the SEGR gas turbine system 52. For example, the sensorfeedback 130 may include feedback from one or more intake oxidantsensors along an oxidant supply path of the oxidant 68, one or moreintake fuel sensors along a fuel supply path of the fuel 70, and one ormore exhaust emissions sensors disposed along the exhaust recirculationpath 110 and/or within the SEGR gas turbine system 52. The intakeoxidant sensors, intake fuel sensors, and exhaust emissions sensors mayinclude temperature sensors, pressure sensors, flow rate sensors, andcomposition sensors. The emissions sensors may includes sensors fornitrogen oxides (e.g., NO_(X) sensors), carbon oxides (e.g., CO sensorsand CO₂ sensors), sulfur oxides (e.g., SO_(X) sensors), hydrogen (e.g.,H₂ sensors), oxygen (e.g., O₂ sensors), unburnt hydrocarbons (e.g., HCsensors), or other products of incomplete combustion, or any combinationthereof.

Using this feedback 130, the control system 100 may adjust (e.g.,increase, decrease, or maintain) the intake flow of exhaust gas 66,oxidant 68, and/or fuel 70 into the SEGR gas turbine system 52 (amongother operational parameters) to maintain the equivalence ratio within asuitable range, e.g., between approximately 0.95 to approximately 1.05,between approximately 0.95 to approximately 1.0, between approximately1.0 to approximately 1.05, or substantially at 1.0. For example, thecontrol system 100 may analyze the feedback 130 to monitor the exhaustemissions (e.g., concentration levels of nitrogen oxides, carbon oxidessuch as CO and CO₂, sulfur oxides, hydrogen, oxygen, unburnthydrocarbons, and other products of incomplete combustion) and/ordetermine the equivalence ratio, and then control one or more componentsto adjust the exhaust emissions (e.g., concentration levels in theexhaust gas 42) and/or the equivalence ratio. The controlled componentsmay include any of the components illustrated and described withreference to the drawings, including but not limited to, valves alongthe supply paths for the oxidant 68, the fuel 70, and the exhaust gas66; an oxidant compressor, a fuel pump, or any components in the EGprocessing system 54; any components of the SEGR gas turbine system 52,or any combination thereof. The controlled components may adjust (e.g.,increase, decrease, or maintain) the flow rates, temperatures,pressures, or percentages (e.g., equivalence ratio) of the oxidant 68,the fuel 70, and the exhaust gas 66 that combust within the SEGR gasturbine system 52. The controlled components also may include one ormore gas treatment systems, such as catalyst units (e.g., oxidationcatalyst units), supplies for the catalyst units (e.g., oxidation fuel,heat, electricity, etc.), gas purification and/or separation units(e.g., solvent based separators, absorbers, flash tanks, etc.), andfiltration units. The gas treatment systems may help reduce variousexhaust emissions along the exhaust recirculation path 110, a vent path(e.g., exhausted into the atmosphere), or an extraction path to the EGsupply system 78.

In certain embodiments, the control system 100 may analyze the feedback130 and control one or more components to maintain or reduce emissionslevels (e.g., concentration levels in the exhaust gas 42, 60, 95) to atarget range, such as less than approximately 10, 20, 30, 40, 50, 100,200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts permillion by volume (ppmv). These target ranges may be the same ordifferent for each of the exhaust emissions, e.g., concentration levelsof nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen,unburnt hydrocarbons, and other products of incomplete combustion. Forexample, depending on the equivalence ratio, the control system 100 mayselectively control exhaust emissions (e.g., concentration levels) ofoxidant (e.g., oxygen) within a target range of less than approximately10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv;carbon monoxide (CO) within a target range of less than approximately20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides(NO_(X)) within a target range of less than approximately 50, 100, 200,300, 400, or 500 ppmv. In certain embodiments operating with asubstantially stoichiometric equivalence ratio, the control system 100may selectively control exhaust emissions (e.g., concentration levels)of oxidant (e.g., oxygen) within a target range of less thanapproximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; andcarbon monoxide (CO) within a target range of less than approximately500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodimentsoperating with a fuel-lean equivalence ratio (e.g., betweenapproximately 0.95 to 1.0), the control system 100 may selectivelycontrol exhaust emissions (e.g., concentration levels) of oxidant (e.g.,oxygen) within a target range of less than approximately 500, 600, 700,800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide(CO) within a target range of less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g.,NO_(X)) within a target range of less than approximately 50, 100, 150,200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merelyexamples, and are not intended to limit the scope of the disclosedembodiments.

The control system 100 also may be coupled to a local interface 132 anda remote interface 134. For example, the local interface 132 may includea computer workstation disposed on-site at the turbine-based servicesystem 14 and/or the hydrocarbon production system 12. In contrast, theremote interface 134 may include a computer workstation disposedoff-site from the turbine-based service system 14 and the hydrocarbonproduction system 12, such as through an internet connection. Theseinterfaces 132 and 134 facilitate monitoring and control of theturbine-based service system 14, such as through one or more graphicaldisplays of sensor feedback 130, operational parameters, and so forth.

Again, as noted above, the controller 118 includes a variety of controls124, 126, and 128 to facilitate control of the turbine-based servicesystem 14. The steam turbine control 124 may receive the sensor feedback130 and output control commands to facilitate operation of the steamturbine 104. For example, the steam turbine control 124 may receive thesensor feedback 130 from the HRSG 56, the machinery 106, temperature andpressure sensors along a path of the steam 62, temperature and pressuresensors along a path of the water 108, and various sensors indicative ofthe mechanical power 72 and the electrical power 74. Likewise, the SEGRgas turbine system control 126 may receive sensor feedback 130 from oneor more sensors disposed along the SEGR gas turbine system 52, themachinery 106, the EG processing system 54, or any combination thereof.For example, the sensor feedback 130 may be obtained from temperaturesensors, pressure sensors, clearance sensors, vibration sensors, flamesensors, fuel composition sensors, exhaust gas composition sensors, orany combination thereof, disposed within or external to the SEGR gasturbine system 52. Finally, the machinery control 128 may receive sensorfeedback 130 from various sensors associated with the mechanical power72 and the electrical power 74, as well as sensors disposed within themachinery 106. Each of these controls 124, 126, and 128 uses the sensorfeedback 130 to improve operation of the turbine-based service system14.

In the illustrated embodiment, the SEGR gas turbine system control 126may execute instructions to control the quantity and quality of theexhaust gas 42, 60, 95 in the EG processing system 54, the EG supplysystem 78, the hydrocarbon production system 12, and/or the othersystems 84. For example, the SEGR gas turbine system control 126 maymaintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in theexhaust gas 60 below a threshold suitable for use with the exhaust gasinjection EOR system 112. In certain embodiments, the threshold levelsmay be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen)and/or unburnt fuel by volume of the exhaust gas 42, 60; or thethreshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (andother exhaust emissions) may be less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or5000 parts per million by volume (ppmv) in the exhaust gas 42, 60. Byfurther example, in order to achieve these low levels of oxidant (e.g.,oxygen) and/or unburnt fuel, the SEGR gas turbine system control 126 maymaintain an equivalence ratio for combustion in the SEGR gas turbinesystem 52 between approximately 0.95 and approximately 1.05. The SEGRgas turbine system control 126 also may control the EG extraction system80 and the EG treatment system 82 to maintain the temperature, pressure,flow rate, and gas composition of the exhaust gas 42, 60, 95 withinsuitable ranges for the exhaust gas injection EOR system 112, thepipeline 86, the storage tank 88, and the carbon sequestration system90. As discussed above, the EG treatment system 82 may be controlled topurify and/or separate the exhaust gas 42 into one or more gas streams95, such as the CO₂ rich, N₂ lean stream 96, the intermediateconcentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. Inaddition to controls for the exhaust gas 42, 60, and 95, the controls124, 126, and 128 may execute one or more instructions to maintain themechanical power 72 within a suitable power range, or maintain theelectrical power 74 within a suitable frequency and power range.

FIG. 3 is a diagram of embodiment of the system 10, further illustratingdetails of the SEGR gas turbine system 52 for use with the hydrocarbonproduction system 12 and/or other systems 84. In the illustratedembodiment, the SEGR gas turbine system 52 includes a gas turbine engine150 coupled to the EG processing system 54. The illustrated gas turbineengine 150 includes a compressor section 152, a combustor section 154,and an expander section or turbine section 156. The compressor section152 includes one or more exhaust gas compressors or compressor stages158, such as 1 to 20 stages of rotary compressor blades disposed in aseries arrangement. Likewise, the combustor section 154 includes one ormore combustors 160, such as 1 to 20 combustors 160 distributedcircumferentially about a rotational axis 162 of the SEGR gas turbinesystem 52. Furthermore, each combustor 160 may include one or more fuelnozzles 164 configured to inject the exhaust gas 66, the oxidant 68,and/or the fuel 70. For example, a head end portion 166 of eachcombustor 160 may house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164,which may inject streams or mixtures of the exhaust gas 66, the oxidant68, and/or the fuel 70 into a combustion portion 168 (e.g., combustionchamber) of the combustor 160.

The fuel nozzles 164 may include any combination of premix fuel nozzles164 (e.g., configured to premix the oxidant 68 and fuel 70 forgeneration of an oxidant/fuel premix flame) and/or diffusion fuelnozzles 164 (e.g., configured to inject separate flows of the oxidant 68and fuel 70 for generation of an oxidant/fuel diffusion flame).Embodiments of the premix fuel nozzles 164 may include swirl vanes,mixing chambers, or other features to internally mix the oxidant 68 andfuel 70 within the nozzles 164, prior to injection and combustion in thecombustion chamber 168. The premix fuel nozzles 164 also may receive atleast some partially mixed oxidant 68 and fuel 70. In certainembodiments, each diffusion fuel nozzle 164 may isolate flows of theoxidant 68 and the fuel 70 until the point of injection, while alsoisolating flows of one or more diluents (e.g., the exhaust gas 66,steam, nitrogen, or another inert gas) until the point of injection. Inother embodiments, each diffusion fuel nozzle 164 may isolate flows ofthe oxidant 68 and the fuel 70 until the point of injection, whilepartially mixing one or more diluents (e.g., the exhaust gas 66, steam,nitrogen, or another inert gas) with the oxidant 68 and/or the fuel 70prior to the point of injection. In addition, one or more diluents(e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) may beinjected into the combustor (e.g., into the hot products of combustion)either at or downstream from the combustion zone, thereby helping toreduce the temperature of the hot products of combustion and reduceemissions of NO_(X) (e.g., NO and NO₂). Regardless of the type of fuelnozzle 164, the SEGR gas turbine system 52 may be controlled to providesubstantially stoichiometric combustion of the oxidant 68 and fuel 70.

In diffusion combustion embodiments using the diffusion fuel nozzles164, the fuel 70 and oxidant 68 generally do not mix upstream from thediffusion flame, but rather the fuel 70 and oxidant 68 mix and reactdirectly at the flame surface and/or the flame surface exists at thelocation of mixing between the fuel 70 and oxidant 68. In particular,the fuel 70 and oxidant 68 separately approach the flame surface (ordiffusion boundary/interface), and then diffuse (e.g., via molecular andviscous diffusion) along the flame surface (or diffusionboundary/interface) to generate the diffusion flame. It is noteworthythat the fuel 70 and oxidant 68 may be at a substantially stoichiometricratio along this flame surface (or diffusion boundary/interface), whichmay result in a greater flame temperature (e.g., a peak flametemperature) along this flame surface. The stoichiometric fuel/oxidantratio generally results in a greater flame temperature (e.g., a peakflame temperature), as compared with a fuel-lean or fuel-richfuel/oxidant ratio. As a result, the diffusion flame may besubstantially more stable than a premix flame, because the diffusion offuel 70 and oxidant 68 helps to maintain a stoichiometric ratio (andgreater temperature) along the flame surface. Although greater flametemperatures can also lead to greater exhaust emissions, such as NO_(X)emissions, the disclosed embodiments use one or more diluents to helpcontrol the temperature and emissions while still avoiding any premixingof the fuel 70 and oxidant 68. For example, the disclosed embodimentsmay introduce one or more diluents separate from the fuel 70 and oxidant68 (e.g., after the point of combustion and/or downstream from thediffusion flame), thereby helping to reduce the temperature and reducethe emissions (e.g., NO_(x) emissions) produced by the diffusion flame.

In operation, as illustrated, the compressor section 152 receives andcompresses the exhaust gas 66 from the EG processing system 54, andoutputs a compressed exhaust gas 170 to each of the combustors 160 inthe combustor section 154. Upon combustion of the fuel 60, oxidant 68,and exhaust gas 170 within each combustor 160, additional exhaust gas orproducts of combustion 172 (i.e., combustion gas) is routed into theturbine section 156. Similar to the compressor section 152, the turbinesection 156 includes one or more turbines or turbine stages 174, whichmay include a series of rotary turbine blades. These turbine blades arethen driven by the products of combustion 172 generated in the combustorsection 154, thereby driving rotation of a shaft 176 coupled to themachinery 106. Again, the machinery 106 may include a variety ofequipment coupled to either end of the SEGR gas turbine system 52, suchas machinery 106, 178 coupled to the turbine section 156 and/ormachinery 106, 180 coupled to the compressor section 152. In certainembodiments, the machinery 106, 178, 180 may include one or moreelectrical generators, oxidant compressors for the oxidant 68, fuelpumps for the fuel 70, gear boxes, or additional drives (e.g. steamturbine 104, electrical motor, etc.) coupled to the SEGR gas turbinesystem 52. Non-limiting examples are discussed in further detail belowwith reference to TABLE 1. As illustrated, the turbine section 156outputs the exhaust gas 60 to recirculate along the exhaustrecirculation path 110 from an exhaust outlet 182 of the turbine section156 to an exhaust inlet 184 into the compressor section 152. Along theexhaust recirculation path 110, the exhaust gas 60 passes through the EGprocessing system 54 (e.g., the HRSG 56 and/or the EGR system 58) asdiscussed in detail above.

Again, each combustor 160 in the combustor section 154 receives, mixes,and stoichiometrically combusts the compressed exhaust gas 170, theoxidant 68, and the fuel 70 to produce the additional exhaust gas orproducts of combustion 172 to drive the turbine section 156. In certainembodiments, the oxidant 68 is compressed by an oxidant compressionsystem 186, such as a main oxidant compression (MOC) system (e.g., amain air compression (MAC) system) having one or more oxidantcompressors (MOCs). The oxidant compression system 186 includes anoxidant compressor 188 coupled to a drive 190. For example, the drive190 may include an electric motor, a combustion engine, or anycombination thereof. In certain embodiments, the drive 190 may be aturbine engine, such as the gas turbine engine 150. Accordingly, theoxidant compression system 186 may be an integral part of the machinery106. In other words, the compressor 188 may be directly or indirectlydriven by the mechanical power 72 supplied by the shaft 176 of the gasturbine engine 150. In such an embodiment, the drive 190 may beexcluded, because the compressor 188 relies on the power output from theturbine engine 150. However, in certain embodiments employing more thanone oxidant compressor is employed, a first oxidant compressor (e.g., alow pressure (LP) oxidant compressor) may be driven by the drive 190while the shaft 176 drives a second oxidant compressor (e.g., a highpressure (HP) oxidant compressor), or vice versa. For example, inanother embodiment, the HP MOC is driven by the drive 190 and the LPoxidant compressor is driven by the shaft 176. In the illustratedembodiment, the oxidant compression system 186 is separate from themachinery 106. In each of these embodiments, the compression system 186compresses and supplies the oxidant 68 to the fuel nozzles 164 and thecombustors 160. Accordingly, some or all of the machinery 106, 178, 180may be configured to increase the operational efficiency of thecompression system 186 (e.g., the compressor 188 and/or additionalcompressors).

The variety of components of the machinery 106, indicated by elementnumbers 106A, 106B, 106C, 106D, 106E, and 106F, may be disposed alongthe line of the shaft 176 and/or parallel to the line of the shaft 176in one or more series arrangements, parallel arrangements, or anycombination of series and parallel arrangements. For example, themachinery 106, 178, 180 (e.g., 106A through 106F) may include any seriesand/or parallel arrangement, in any order, of: one or more gearboxes(e.g., parallel shaft, epicyclic gearboxes), one or more compressors(e.g., oxidant compressors, booster compressors such as EG boostercompressors), one or more power generation units (e.g., electricalgenerators), one or more drives (e.g., steam turbine engines, electricalmotors), heat exchange units (e.g., direct or indirect heat exchangers),clutches, or any combination thereof. The compressors may include axialcompressors, radial or centrifugal compressors, or any combinationthereof, each having one or more compression stages. Regarding the heatexchangers, direct heat exchangers may include spray coolers (e.g.,spray intercoolers), which inject a liquid spray into a gas flow (e.g.,oxidant flow) for direct cooling of the gas flow. Indirect heatexchangers may include at least one wall (e.g., a shell and tube heatexchanger) separating first and second flows, such as a fluid flow(e.g., oxidant flow) separated from a coolant flow (e.g., water, air,refrigerant, or any other liquid or gas coolant), wherein the coolantflow transfers heat from the fluid flow without any direct contact.Examples of indirect heat exchangers include intercooler heat exchangersand heat recovery units, such as heat recovery steam generators. Theheat exchangers also may include heaters. As discussed in further detailbelow, each of these machinery components may be used in variouscombinations as indicated by the non-limiting examples set forth inTABLE 1.

Generally, the machinery 106, 178, 180 may be configured to increase theefficiency of the compression system 186 by, for example, adjustingoperational speeds of one or more oxidant compressors in the system 186,facilitating compression of the oxidant 68 through cooling, and/orextraction of surplus power. The disclosed embodiments are intended toinclude any and all permutations of the foregoing components in themachinery 106, 178, 180 in series and parallel arrangements, whereinone, more than one, all, or none of the components derive power from theshaft 176. As illustrated below, TABLE 1 depicts some non-limitingexamples of arrangements of the machinery 106, 178, 180 disposedproximate and/or coupled to the compressor and turbine sections 152,156.

TABLE 1 106A 106B 106C 106D 106E 106F MOC GEN MOC GBX GEN LP HP GEN MOCMOC HP GBX LP GEN MOC MOC MOC GBX GEN MOC HP GBX GEN LP MOC MOC MOC GBXGEN MOC GBX DRV DRV GBX LP HP GBX GEN MOC MOC DRV GBX HP LP GEN MOC MOCHP GBX LP GEN MOC CLR MOC HP GBX LP GBX GEN MOC CLR MOC HP GBX LP GENMOC HTR MOC STGN MOC GEN DRV MOC DRV GEN DRV MOC GEN DRV CLU MOC GEN DRVCLU MOC GBX GEN

As illustrated above in TABLE 1, a cooling unit is represented as CLR, aclutch is represented as CLU, a drive is represented by DRV, a gearboxis represented as GBX, a generator is represented by GEN, a heating unitis represented by HTR, a main oxidant compressor unit is represented byMOC, with low pressure and high pressure variants being represented asLP MOC and HP MOC, respectively, and a steam generator unit isrepresented as STGN. Although TABLE 1 illustrates the machinery 106,178, 180 in sequence toward the compressor section 152 or the turbinesection 156, TABLE 1 is also intended to cover the reverse sequence ofthe machinery 106, 178, 180. In TABLE 1, any cell including two or morecomponents is intended to cover a parallel arrangement of thecomponents. TABLE 1 is not intended to exclude any non-illustratedpermutations of the machinery 106, 178, 180. These components of themachinery 106, 178, 180 may enable feedback control of temperature,pressure, and flow rate of the oxidant 68 sent to the gas turbine engine150. As discussed in further detail below, the oxidant 68 and the fuel70 may be supplied to the gas turbine engine 150 at locationsspecifically selected to facilitate isolation and extraction of thecompressed exhaust gas 170 without any oxidant 68 or fuel 70 degradingthe quality of the exhaust gas 170.

The EG supply system 78, as illustrated in FIG. 3, is disposed betweenthe gas turbine engine 150 and the target systems (e.g., the hydrocarbonproduction system 12 and the other systems 84). In particular, the EGsupply system 78, e.g., the EG extraction system (EGES) 80), may becoupled to the gas turbine engine 150 at one or more extraction points76 along the compressor section 152, the combustor section 154, and/orthe turbine section 156. For example, the extraction points 76 may belocated between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8,9, or 10 interstage extraction points 76 between compressor stages. Eachof these interstage extraction points 76 provides a differenttemperature and pressure of the extracted exhaust gas 42. Similarly, theextraction points 76 may be located between adjacent turbine stages,such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76between turbine stages. Each of these interstage extraction points 76provides a different temperature and pressure of the extracted exhaustgas 42. By further example, the extraction points 76 may be located at amultitude of locations throughout the combustor section 154, which mayprovide different temperatures, pressures, flow rates, and gascompositions. Each of these extraction points 76 may include an EGextraction conduit, one or more valves, sensors, and controls, which maybe used to selectively control the flow of the extracted exhaust gas 42to the EG supply system 78.

The extracted exhaust gas 42, which is distributed by the EG supplysystem 78, has a controlled composition suitable for the target systems(e.g., the hydrocarbon production system 12 and the other systems 84).For example, at each of these extraction points 76, the exhaust gas 170may be substantially isolated from injection points (or flows) of theoxidant 68 and the fuel 70. In other words, the EG supply system 78 maybe specifically designed to extract the exhaust gas 170 from the gasturbine engine 150 without any added oxidant 68 or fuel 70. Furthermore,in view of the stoichiometric combustion in each of the combustors 160,the extracted exhaust gas 42 may be substantially free of oxygen andfuel. The EG supply system 78 may route the extracted exhaust gas 42directly or indirectly to the hydrocarbon production system 12 and/orother systems 84 for use in various processes, such as enhanced oilrecovery, carbon sequestration, storage, or transport to an offsitelocation. However, in certain embodiments, the EG supply system 78includes the EG treatment system (EGTS) 82 for further treatment of theexhaust gas 42, prior to use with the target systems. For example, theEG treatment system 82 may purify and/or separate the exhaust gas 42into one or more streams 95, such as the CO₂ rich, N₂ lean stream 96,the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂rich stream 98. These treated exhaust gas streams 95 may be usedindividually, or in any combination, with the hydrocarbon productionsystem 12 and the other systems 84 (e.g., the pipeline 86, the storagetank 88, and the carbon sequestration system 90).

Similar to the exhaust gas treatments performed in the EG supply system78, the EG processing system 54 may include a plurality of exhaust gas(EG) treatment components 192, such as indicated by element numbers 194,196, 198, 200, 202, 204, 206, 208, and 210. These EG treatmentcomponents 192 (e.g., 194 through 210) may be disposed along the exhaustrecirculation path 110 in one or more series arrangements, parallelarrangements, or any combination of series and parallel arrangements.For example, the EG treatment components 192 (e.g., 194 through 210) mayinclude any series and/or parallel arrangement, in any order, of: one ormore heat exchangers (e.g., heat recovery units such as heat recoverysteam generators, condensers, coolers, or heaters), catalyst systems(e.g., oxidation catalyst systems), particulate and/or water removalsystems (e.g., inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, or any combinationthereof. In certain embodiments, the catalyst systems may include anoxidation catalyst, a carbon monoxide reduction catalyst, a nitrogenoxides reduction catalyst, an aluminum oxide, a zirconium oxide, asilicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, acobalt oxide, or a mixed metal oxide, or a combination thereof. Thedisclosed embodiments are intended to include any and all permutationsof the foregoing components 192 in series and parallel arrangements. Asillustrated below, TABLE 2 depicts some non-limiting examples ofarrangements of the components 192 along the exhaust recirculation path110.

TABLE 2 194 196 198 200 202 204 206 208 210 CU HRU BB MRU PRU CU HRU HRUBB MRU PRU DIL CU HRSG HRSG BB MRU PRU OCU HRU OCU HRU OCU BB MRU PRUHRU HRU BB MRU PRU CU CU HRSG HRSG BB MRU PRU DIL OCU OCU OCU HRSG OCUHRSG OCU BB MRU PRU DIL OCU OCU OCU HRSG HRSG BB COND INER WFIL CFIL DILST ST OCU OCU BB COND INER FIL DIL HRSG HRSG ST ST OCU HRSG HRSG OCU BBMRU MRU PRU PRU ST ST HE WFIL INER FIL COND CFIL CU HRU HRU HRU BB MRUPRU PRU DIL COND COND COND HE INER FIL COND CFIL WFIL

As illustrated above in TABLE 2, a catalyst unit is represented by CU,an oxidation catalyst unit is represented by OCU, a booster blower isrepresented by BB, a heat exchanger is represented by HX, a heatrecovery unit is represented by HRU, a heat recovery steam generator isrepresented by HRSG, a condenser is represented by COND, a steam turbineis represented by ST, a particulate removal unit is represented by PRU,a moisture removal unit is represented by MRU, a filter is representedby FIL, a coalescing filter is represented by CFIL, a water impermeablefilter is represented by WFIL, an inertial separator is represented byINER, and a diluent supply system (e.g., steam, nitrogen, or other inertgas) is represented by DIL. Although TABLE 2 illustrates the components192 in sequence from the exhaust outlet 182 of the turbine section 156toward the exhaust inlet 184 of the compressor section 152, TABLE 2 isalso intended to cover the reverse sequence of the illustratedcomponents 192. In TABLE 2, any cell including two or more components isintended to cover an integrated unit with the components, a parallelarrangement of the components, or any combination thereof. Furthermore,in context of TABLE 2, the HRU, the HRSG, and the COND are examples ofthe HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL areexamples of the WRU; the INER, FIL, WFIL, and CFIL are examples of thePRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 isnot intended to exclude any non-illustrated permutations of thecomponents 192. In certain embodiments, the illustrated components 192(e.g., 194 through 210) may be partially or completed integrated withinthe HRSG 56, the EGR system 58, or any combination thereof. These EGtreatment components 192 may enable feedback control of temperature,pressure, flow rate, and gas composition, while also removing moistureand particulates from the exhaust gas 60. Furthermore, the treatedexhaust gas 60 may be extracted at one or more extraction points 76 foruse in the EG supply system 78 and/or recirculated to the exhaust inlet184 of the compressor section 152.

As the treated, recirculated exhaust gas 66 passes through thecompressor section 152, the SEGR gas turbine system 52 may bleed off aportion of the compressed exhaust gas along one or more lines 212 (e.g.,bleed conduits or bypass conduits). Each line 212 may route the exhaustgas into one or more heat exchangers 214 (e.g., cooling units), therebycooling the exhaust gas for recirculation back into the SEGR gas turbinesystem 52. For example, after passing through the heat exchanger 214, aportion of the cooled exhaust gas may be routed to the turbine section156 along line 212 for cooling and/or sealing of the turbine casing,turbine shrouds, bearings, and other components. In such an embodiment,the SEGR gas turbine system 52 does not route any oxidant 68 (or otherpotential contaminants) through the turbine section 156 for coolingand/or sealing purposes, and thus any leakage of the cooled exhaust gaswill not contaminate the hot products of combustion (e.g., workingexhaust gas) flowing through and driving the turbine stages of theturbine section 156. By further example, after passing through the heatexchanger 214, a portion of the cooled exhaust gas may be routed alongline 216 (e.g., return conduit) to an upstream compressor stage of thecompressor section 152, thereby improving the efficiency of compressionby the compressor section 152. In such an embodiment, the heat exchanger214 may be configured as an interstage cooling unit for the compressorsection 152. In this manner, the cooled exhaust gas helps to increasethe operational efficiency of the SEGR gas turbine system 52, whilesimultaneously helping to maintain the purity of the exhaust gas (e.g.,substantially free of oxidant and fuel).

FIG. 4 is a flow chart of an embodiment of an operational process 220 ofthe system 10 illustrated in FIGS. 1-3. In certain embodiments, theprocess 220 may be a computer implemented process, which accesses one ormore instructions stored on the memory 122 and executes the instructionson the processor 120 of the controller 118 shown in FIG. 2. For example,each step in the process 220 may include instructions executable by thecontroller 118 of the control system 100 described with reference toFIG. 2.

The process 220 may begin by initiating a startup mode of the SEGR gasturbine system 52 of FIGS. 1-3, as indicated by block 222. For example,the startup mode may involve a gradual ramp up of the SEGR gas turbinesystem 52 to maintain thermal gradients, vibration, and clearance (e.g.,between rotating and stationary parts) within acceptable thresholds. Forexample, during the startup mode 222, the process 220 may begin tosupply a compressed oxidant 68 to the combustors 160 and the fuelnozzles 164 of the combustor section 154, as indicated by block 224. Incertain embodiments, the compressed oxidant may include a compressedair, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogenmixtures, or any combination thereof. For example, the oxidant 68 may becompressed by the oxidant compression system 186 illustrated in FIG. 3.The process 220 also may begin to supply fuel to the combustors 160 andthe fuel nozzles 164 during the startup mode 222, as indicated by block226. During the startup mode 222, the process 220 also may begin tosupply exhaust gas (as available) to the combustors 160 and the fuelnozzles 164, as indicated by block 228. For example, the fuel nozzles164 may produce one or more diffusion flames, premix flames, or acombination of diffusion and premix flames. During the startup mode 222,the exhaust gas 60 being generated by the gas turbine engine 156 may beinsufficient or unstable in quantity and/or quality. Accordingly, duringthe startup mode, the process 220 may supply the exhaust gas 66 from oneor more storage units (e.g., storage tank 88), the pipeline 86, otherSEGR gas turbine systems 52, or other exhaust gas sources.

The process 220 may then combust a mixture of the compressed oxidant,fuel, and exhaust gas in the combustors 160 to produce hot combustiongas 172, as indicated by block 230. In particular, the process 220 maybe controlled by the control system 100 of FIG. 2 to facilitatestoichiometric combustion (e.g., stoichiometric diffusion combustion,premix combustion, or both) of the mixture in the combustors 160 of thecombustor section 154. However, during the startup mode 222, it may beparticularly difficult to maintain stoichiometric combustion of themixture (and thus low levels of oxidant and unburnt fuel may be presentin the hot combustion gas 172). As a result, in the startup mode 222,the hot combustion gas 172 may have greater amounts of residual oxidant68 and/or fuel 70 than during a steady state mode as discussed infurther detail below. For this reason, the process 220 may execute oneor more control instructions to reduce or eliminate the residual oxidant68 and/or fuel 70 in the hot combustion gas 172 during the startup mode.

The process 220 then drives the turbine section 156 with the hotcombustion gas 172, as indicated by block 232. For example, the hotcombustion gas 172 may drive one or more turbine stages 174 disposedwithin the turbine section 156. Downstream of the turbine section 156,the process 220 may treat the exhaust gas 60 from the final turbinestage 174, as indicated by block 234. For example, the exhaust gastreatment 234 may include filtration, catalytic reaction of any residualoxidant 68 and/or fuel 70, chemical treatment, heat recovery with theHRSG 56, and so forth. The process 220 may also recirculate at leastsome of the exhaust gas 60 back to the compressor section 152 of theSEGR gas turbine system 52, as indicated by block 236. For example, theexhaust gas recirculation 236 may involve passage through the exhaustrecirculation path 110 having the EG processing system 54 as illustratedin FIGS. 1-3.

In turn, the recirculated exhaust gas 66 may be compressed in thecompressor section 152, as indicated by block 238. For example, the SEGRgas turbine system 52 may sequentially compress the recirculated exhaustgas 66 in one or more compressor stages 158 of the compressor section152. Subsequently, the compressed exhaust gas 170 may be supplied to thecombustors 160 and fuel nozzles 164, as indicated by block 228. Steps230, 232, 234, 236, and 238 may then repeat, until the process 220eventually transitions to a steady state mode, as indicated by block240. Upon the transition 240, the process 220 may continue to performthe steps 224 through 238, but may also begin to extract the exhaust gas42 via the EG supply system 78, as indicated by block 242. For example,the exhaust gas 42 may be extracted from one or more extraction points76 along the compressor section 152, the combustor section 154, and theturbine section 156 as indicated in FIG. 3. In turn, the process 220 maysupply the extracted exhaust gas 42 from the EG supply system 78 to thehydrocarbon production system 12, as indicated by block 244. Thehydrocarbon production system 12 may then inject the exhaust gas 42 intothe earth 32 for enhanced oil recovery, as indicated by block 246. Forexample, the extracted exhaust gas 42 may be used by the exhaust gasinjection EOR system 112 of the EOR system 18 illustrated in FIGS. 1-3.

FIG. 5 is a flow chart of a process 260 for operating the gas turbineengine 150 with exhaust gas recirculation. In a step 262, the process260 compresses the oxidant 68 in the oxidant compressor 188 to generatecompressed oxidant. Again, the oxidant 68 may include air, oxygen,oxygen-enriched air, oxygen-reduced air, oxygen nitrogen mixtures, orany combination thereof. For example, if the oxidant 68 includes air,then the compressor 188 may include an air compressor. In step 264, theexhaust gas 66 is compressed in a compressor section 152, such as anexhaust gas compressor of the gas turbine engine 150, to generatecompressed exhaust gas 170. In a step 266, the compressed exhaust gas170 and the compressed oxidant are routed from the compressor section152 and the oxidant compressor 188, respectively, to one or morecombustors 160 of the gas turbine engine 150. In a step 268, thecompressed exhaust gas 170 is isolated from the compressed oxidant priorto a flow mixer associated with each combustor 160, as described indetail below. In a step 270, the compressed exhaust gas 170 is splitinto first and second portions with a flow separator associated witheach combustor 160, as described in detail below. In a step 272, thefirst portion of the compressed exhaust gas 170 is extracted for use inone or more applications, such as the oil/gas extraction system 16, theenhanced oil recovery (EOR) system 18, or another system 84. In a step274, the second portion of the compressed exhaust gas 170 is mixed withoxidant to generate an exhaust gas/oxidant mixture using the flow mixer.In a step 276, the exhaust gas/oxidant mixture and the fuel 70 areinjected into a combustion chamber of the combustion portion 168 of thecombustor 160 to provide a combustible mixture. The fuel 70 may eitherbe mixed with the exhaust gas/oxidant mixture in fuel nozzles (e.g., apremix design) or the fuel 70 may be kept separate from the exhaustgas/oxidant mixture until exiting the fuel nozzles (e.g., a diffusiondesign). In a step 278, the combustible mixture is combusted to generatethe combustion gas or exhaust gas 172. In a step 280, the combustion gasor exhaust gas 172 is expanded in the turbine stages 174 of the gasturbine engine 150 to generate the exhaust gas 60. In a step 282, theexpanded exhaust gas 60 is recirculated from the turbine stages 174 tothe compressor stages 158 of the compressor section 152. The process 260may then repeat by compressing oxidant in the oxidant compressor 188 togenerate compressed oxidant in the step 262. With the overall process260 for operating the gas turbine engine 150 shown in FIG. 5 in mind,specific embodiments of the combustor section 154 are shown in FIGS.6-16 and discussed below.

FIG. 6 is a schematic diagram of an embodiment of the combustor section154 that includes various features that are shown in detail in FIGS.7-16. Elements in FIG. 6 in common with those shown in previous figuresare labeled with the same reference numerals. The axial direction of thecombustor 160 is indicated by arrow 294, the radial direction isindicated by arrow 296, and the circumferential direction is indicatedby arrow 298. As shown in FIG. 6, the oxidant compression system 186generates a compressed oxidant 300 that may be provided to variouslocations of the combustor 160. For example, the compressed oxidant 300may be provided to a flow mixer 302 to combine the compressed oxidant300 with the compressed exhaust gas 170. As discussed in detail below,the flow mixer 302 may help to improve mixing of the oxidant 300 andexhaust gas 170 when space or length for mixing is limited. Thecompressed oxidant 300 may include air, oxygen, oxygen-enriched air,oxygen-reduced air, or oxygen nitrogen mixtures. The exhaust gas 170 maybe substantially free of oxygen and unburnt fuel, and may result fromstoichiometric combustion and exhaust gas recirculation, as discussedabove. Thus, the exhaust gas 170 may be used as a diluent with theoxidant 300. Additionally or alternatively, the compressed oxidant 300may be provided to a flow separator 304 that separates the compressedexhaust gas 170 into two or more portions. For example, the flowseparator 304 may provide a portion of the compressed exhaust gas 170 tothe exhaust extraction system 80 as the extracted exhaust gas 42. Inaddition, the flow separator 304 may also help to isolate the oxidant300 from the exhaust gas 170. As shown in FIG. 6, the flow mixer 302 andthe flow separator 304 may be disposed in the head end portion 166 ofthe combustor 160. Further details of the flow mixer 302 and the flowseparator 304 are described below with respect to FIGS. 7-16.

FIG. 7 is a schematic diagram of the head end portion 166 of thecombustor 160. As shown in FIG. 7, the combustor 160 is generallydefined by a combustion casing 320, a flow sleeve 322, and a combustionliner 324. As illustrated, the flow sleeve 322 is disposed about thecombustion liner 324. In certain embodiments, the flow sleeve 322 andthe combustion liner 324 are coaxial with one another to define a firstflow path 326 (e.g., annular passage), which may enable passage of thecompressed exhaust gas 170 for cooling of the combustion liner 324 andfor entry into the head end portion 166. In addition, the combustioncasing 320 and the flow sleeve 322 may define a second flow path 328(e.g., annular passage), which may also enable passage of the compressedexhaust gas 170 for cooling and for entry into the head end portion 166.A first exhaust extraction port 330 may be coupled to the combustioncasing 320. As illustrated, the first exhaust extraction port 330 may bea radial port, thereby extracting the exhaust gas 42 radially 296 fromthe combustor 160. The first exhaust extraction port 330 may convey thecompressed exhaust gas 170 (e.g., exhaust gas 42) from the second flowpath 328 to the exhaust gas extraction system 80. In certainembodiments, a cap 331 may be disposed between the head end portion 166and the combustion portion 168.

As shown in FIG. 7, the flow separator 304 separates the compressedexhaust gas 170 from the oxidant 68. Specifically, the flow separator304 may include the flow sleeve 322 and/or a flow distributor 332, whichmay be disposed between the combustion casing 320 and the combustionliner 324 downstream (with respect to the direction of flowingcompressed exhaust gas 170) of the first exhaust extraction port 330. Inother embodiments, the flow separator 304 may also include other wallsof the combustor 160, such as the combustion casing 320 and thecombustion liner 324. The flow distributor 332 may extend crosswiseacross the first and second flow paths 326 and 328. In certainembodiments, the flow distributor 332 may extend completelycircumferentially 298 around the head end portion 166, as discussed indetail below. In other embodiments, the flow distributor 332 may includea plurality of distributor portions spaced circumferentially 298 aroundthe head end portion 166. For example, the flow distributor 332 mayinclude a first distributor portion 394 and a second distributor portion396 which may be different from one another (e.g., circumferentially 298offset from one another). In various embodiments, the flow distributormay include 2, 3, 4, 5, 6, or more distributor portions. In certainembodiments, the first distributor portion 394 may include a pluralityof first inserts 398 disposed circumferentially 298 and the seconddistributor portion 396 may include a plurality of second inserts 400disposed circumferentially 298.

As discussed in detail below, the flow distributor 332 may include oneor more paths or passages for routing of various fluids (e.g., gases)into, out of, or to certain portions of the combustor 160. Thus, bydisposing a plurality of flow distributors 332 circumferentially 298about the head end portion 166, differential flows of exhaust gas 42,oxidant 68, compressed exhaust gas 170, and so forth may be providedcircumferentially 298 about the head end portion 166, which may includeexhaust gas extraction, oxidant injection, flow toward the cap 331, flowinto mixing regions, or any combination thereof.

As shown in FIG. 7, the flow distributor 332 of the first distributorportion 394 may include an exhaust gas flow path 334 that routes thecompressed exhaust gas 170 in the second flow path 328 into the head endportion 166. Specifically, the exhaust gas flow path 334 may route thecompressed exhaust gas 170 to a cooling region 335 adjacent the cap 331in the head end portion 166 to help cool the cap 331. In certainembodiments, the exhaust gas flow path 334 may be referred to moregenerally as a cooling gas flow path, especially if a gas other than thecompressed exhaust gas 170 is used for cooling.

As illustrated in FIG. 7, an oxidant intake port 336 may be coupled tothe flow distributor 332 of both the first and section portions 394 and396. As illustrated, the oxidant intake port 336 may be a radial port,thereby supplying the oxidant 68 to the combustor 160 radially 296. Theoxidant intake port 336 may be configured to route the oxidant 68 fromthe oxidant compression system 186 to the combustor 160. In certainembodiments, the flow distributor 332 may include an oxidant flow path338 that routes the oxidant 68 from the oxidant intake port 336 into thehead end portion 166. Specifically, the oxidant flow path 338 may routethe oxidant 68 to a mixing region 346 adjacent the flow distributor 332to provide an oxidant-exhaust mixture 348.

As illustrated in FIG. 7, a second exhaust extraction port 344 may becoupled to the flow distributor 332 of the second distributor portion396. As illustrated, the second exhaust extraction port 344 may be aradial port, thereby extracting the compressed exhaust gas 170 radially296 from the combustor 160. In certain embodiments, the flow distributor332 of the second distributor portion 396 may include an exhaust gasextraction flow path 345 that routes the exhaust gas 42 through the flowdistributor 332 to the exhaust extraction system 80.

As shown in FIG. 7, the flow distributors 332 of both the first andsecond portions 394 and 396 provide the oxidant 68 to the mixing region346. However, the flow distributor 332 of the first distributor portion394 provides the compressed exhaust gas 170 to the cooling region 335and the flow distributor of the first portion 396 provides thecompressed exhaust gas 170 to the exhaust extraction system 80. Thus, incertain embodiments, the relative sizes of the first and second portions394 and 396 may be adjusted to achieve a desired allocation of thecompressed exhaust gas 170 for cooling and extraction. In addition, asdescribed below, the circumferential 298 placement of the first andsecond portions 394 and 396 may be adjusted for various reasons, such asto provide additional cooling where desired or extraction where space isavailable about the combustor 160. For example, the spacing between thefirst and second portions 394 (e.g., inserts) may be varied. In furtherembodiments, the plurality of first inserts 398 may differ from oneanother. For example, the diameters of the exhaust gas paths 334 may notall be the same and/or the diameters of the oxidant flow paths 338 maydiffer from one another. Similarly, the plurality of second inserts 400may also differ from one another. Thus, the placement of the flowdistributors 332, spacing of flow distributors 332, diameters, shapes,sizes, positions, and/or placement of passages of the flow distributors332 may be used to vary the circumferential 298 distribution about thehead end portion 166 of the flows of the exhaust gas 42, oxidant 68,compressed exhaust gas 170, and so forth.

In certain embodiments, the flow distributor 332 does not extendcompletely circumferentially 298 about the head end portion 166, asdiscussed in detail below. Thus, some of the compressed exhaust gas 170may flow past, or bypass, one or more flow distributors 332 (e.g., theflow separator 304) through intermediate spaces between flowdistributors 332 to combine with the oxidant 68 to form theoxidant-exhaust mixture 348. As shown in FIG. 7, several walls aredisposed downstream of the flow distributor 332. Specifically, a firstwall 402 is disposed circumferentially 298 about the head end portion166, a second wall 404 is disposed circumferentially 298 about the firstwall 402 to define the first flow path 326, and a third wall 406 isdisposed circumferentially 298 about the second wall 404. In certainembodiments, there may be no flow path between the second and thirdwalls 404 and 406. In other words, the second and third walls 404 and406 may be considered a single, integral wall. As shown in FIG. 7, thefirst wall 402 may generally coincide with the combustion liner 324, thesecond wall 404 may generally coincide with the flow sleeve 322, and thethird wall 406 may generally coincide with the combustion casing 320.However, in other embodiments, the first, second, and third walls 402,402, and 406 may be disposed at different locations. As shown in FIG. 7,the mixing region 346 is enclosed by the first and second walls 402 and404.

Next, the oxidant-exhaust mixture 348 may travel to an end plate 340before turning and entering the fuel nozzles 164. The fuel 70 may besupplied to the combustor 160 via a fuel supply system 342.Specifically, an axial fuel manifold 408 may supply the fuel 70 axially294 to one or more fuel intake ports 410 coupled to a central portion341 of the end plate 340. As shown in FIG. 7, the oxidant-exhaustmixture 348 then enters the fuel nozzles 164 to be combined with thefuel 70 from the fuel supply system 342 before being combusted in thecombustion portion 168 (e.g., premix fuel nozzles). In otherembodiments, the oxidant-exhaust mixture 348 is not combined with thefuel 70 until exiting the fuel nozzles 164 (e.g., diffusion fuelnozzles). In addition, the controller 118 may be used to control theexhaust extraction system 80 and the oxidant compression system 186.

FIG. 8 is a radial cross-sectional view of the combustor 160 taken alongthe line 8-8 of FIG. 7. As shown in FIG. 8, the path of the compressedexhaust gas 170 in the second flow path 328 may be blocked by an annularring 360, which may be part of the flow distributor 332. Thus, for thefirst inserts 398 (e.g., the first distributor portion 394), thecompressed exhaust gas 170 in the second flow path 328 is forced intothe exhaust gas path 334. Specifically, the compressed exhaust gas 170enters an entrance 362 of the exhaust gas path 334 and enters the headend chamber 166 through an exit 364 to help cool the cap 331. For thesecond inserts 400 (e.g., the second distributor portion 396), thecompressed exhaust gas 170 in the second flow path 328 is forced intothe exhaust gas extraction flow path 345. Specifically, the compressedexhaust gas 170 enters an entrance 368 of the exhaust gas extractionflow path 345 and exits an exit 370 to be extracted through the secondexhaust extraction port 344. In addition, the oxidant 68 enters anoxidant entrance 420 of the oxidant path 400 and exits an oxidant exit422 into the first flow path 326 to mix with the compressed exhaust gas170 to generate the oxidant-exhaust mixture 348.

As shown in FIG. 8, a plurality of first inserts 398 may be spaced apartfrom one another circumferentially 298 about the head end portion 166(e.g., fuel nozzles 164) and a plurality of second inserts 400 may alsobe spaced apart from one another circumferentially 298. Thus, thecompressed exhaust gas 170 in the first flow path 326 passes throughgaps 366 between the first and second inserts 398 and 400. In otherembodiments, the first and second inserts 398 and 400 may not be evenlyspaced apart from one another circumferentially 298. For example, theplurality of first and second inserts 398 and 400 may be disposed withinapproximately 60 degrees of top dead center of the combustor 160 becauseof packaging constraints associated with can-annular combustors. Inaddition, the first and second inserts 398 and 400 may not bedistributed circumferentially 298 in an alternating arrangement, asshown in FIG. 8. For example, if more extraction of the compressedexhaust gas 170 is desired, a pattern of two of the second inserts 400followed circumferentially 298 by one of the first inserts 398 may berepeated circumferentially 298. If additional extraction of thecompressed exhaust gas 170 is desired, a pattern of 3, 4, 5, 6 or moreof the second inserts 400 followed circumferentially 298 by one of thefirst inserts 398 may be repeated circumferentially 298. In otherembodiments, the arrangement of the first and second inserts 398 and 400may not follow a repeating pattern. For example, the first inserts 398may be disposed generally near top dead center of the combustor and thesecond inserts 400 may be disposed generally opposite from top deadcenter. Thus, the first and second inserts 398 and 400 may be arrangedcircumferentially 298 to achieve desired flow rates and/or placement ofextracted compressed exhaust gas 170 and compressed exhaust gas 170 usedfor cooling the cap 331.

FIG. 9 is a radial cross-sectional view of the combustor 160 taken alongthe line 8-8 of FIG. 7. As shown in FIG. 9, a second annular ring 380may be disposed in the first flow path 326. The second annular ring 380,which may be part of the flow distributor 332, may include a pluralityof openings 382 for the compressed exhaust gas 170 to pass through.Thus, the second annular ring 380 and the openings 382 may be used toadjust the flow rate of the compressed exhaust gas 170 through the firstflow path 326. For example, providing more openings 382 may enableadditional compressed exhaust gas 170 to flow through the first flowpath 326. The openings 382 may be disposed circumferentially 298 aboutthe fuel nozzles 164. Although the openings 382 are shown as circularopenings in FIG. 9, the sizes, shapes, and/or locations of the openings382 may be adjusted to provide the desired flow rate of the compressedexhaust gas 170 through the first flow path 326 and/or to accommodatepackaging limitations of individual combustors 160. As shown in FIG. 9,a plurality of entrances 362 for the exhaust gas flow path 334 may bedisposed circumferentially 298 in the first annular ring 360. In certainembodiments, the number of entrances 362 may be adjusted to provide adesired amount of cooling of the cap 331. In addition, the locations ofthe entrances 362 may be varied to provide cooling of the cap 331 wheredesired. In addition, a plurality of entrances 368 of the exhaust gasextraction flow path 345 may be disposed circumferentially 298 in thefirst annular ring 360. Thus, the entrances 362 may be disposed in oneor more arcuate portions of the head end portion 166 (e.g., firstannular ring 360) and the entrances 368 may be disposed in one or moredifferent arcuate portions. Although the entrances 362 and 368 are shownspaced apart from one another circumferentially 298 in FIG. 9, in otherembodiments, the entrances 362 and 368 may be disposed withinapproximately 60 degrees of top dead center of the combustor 160.

FIG. 10 is a cross-sectional view of an embodiment of the combustor 160.Elements in FIG. 10 in common with those shown in FIG. 7 are labeledwith the same reference numerals. The cross-sectional view shown in FIG.10 is similar to the view shown in FIG. 7, but focuses on the shape andarrangement of the components of the combustor 160 near the firstdistributor portion 394 of the flow distributor 332. For example, in theillustrated embodiment, the second flow path 328 includes a contouredsurface 390 near the flow distributor 332 to help guide the compressedexhaust gas 170 into the entrance 362. In addition, the contouredsurface 390 may be used to adjust the flow rate of the compressedexhaust gas 170 through the exhaust gas flow path 334 in the flowdistributor 332. Similarly, the first flow path 326 may include variouscontoured surfaces to adjust the flow rate of the compressed exhaust gas170 through the first flow path 326. Further, the first and second walls402 and 404 may converge in the direction of the flow of theoxidant-exhaust mixture 348, which may help increase the velocity of theoxidant-exhaust mixture 348. As discussed below, numbers, placement,shapes, and/or diameters of the exhaust gas flow path 334 and theoxidant flow path 338 may be varied in a plurality of flow distributors332 disposed circumferentially 298 about the head end portion 166.

FIG. 11 is a cross-sectional view of an embodiment of the combustor 160.Elements in FIG. 11 in common with those shown in FIG. 7 are labeledwith the same reference numerals. The cross-sectional view shown in FIG.11 is similar to the view shown in FIG. 7, but focuses on the shape andarrangement of the components of the combustor 160 near the seconddistributor portion 396 of the flow distributor 332. For example, in theillustrated embodiment, the second flow path 328 includes the contouredsurface 390 near the flow distributor 332 to help guide the compressedexhaust gas 170 into the entrance 368 of the exhaust gas extraction flowpath 345. In addition, the contoured surface 390 may be used to adjustthe flow rate of the compressed exhaust gas 170 through the exhaust gasextraction flow path 345 in the flow distributor 332. Similarly, thefirst flow path 326 may include various contoured surfaces to adjust theflow rate of the compressed exhaust gas 170 through the first flow path326. Further, the first and second walls 402 and 404 may converge in thedirection of the flow of the oxidant-exhaust mixture 348, which may helpincrease the velocity of the oxidant-exhaust mixture 348. As discussedbelow, numbers, placement, shapes, and/or diameters of the exhaust gasextraction flow path 345 and the oxidant flow path 338 may be varied ina plurality of flow distributors 332 disposed circumferentially 298about the head end portion 166.

FIG. 12 is a schematic diagram of an embodiment of the head end portion166 of the combustor section 154. Elements in FIG. 12 in common withthose shown in FIG. 7 are labeled referenced with the same referencenumerals. As shown in FIG. 12, a portion of the compressed exhaust gas170 in the second flow path 328 exits the combustor 160 radially 296through the first exhaust gas extraction port 330 to enter the exhaustgas extraction system 80. Another portion of the compressed exhaust gas170 in the second flow path 328 flows toward the first distributorportion 394 of the flow distributor 332. Prior to reaching the flowdistributor 332, the compressed exhaust gas 170 combines with theoxidant 68 entering the combustor 160 radially 296 through the oxidantintake port 336 to produce the oxidant-exhaust mixture 348 in the mixingregion 346. The oxidant-exhaust mixture 348 then enters the entrance 362of the exhaust gas path 334 and enters the head end chamber 166 throughthe exit 364 to help cool the cap 331. The exhaust gas path 334 may alsobe referred to more generally as a cooling gas path as theoxidant-exhaust mixture 348 includes more than just exhaust gas (i.e.,oxidant 68). Backflow of the oxidant 68 into the first exhaustextraction port 330 may be blocked by the flow of the compressed exhaustgas 170 toward the flow distributor 332. In further embodiments, abaffle, wall, or similar device may be used to prevent the oxidant 68from entering the first exhaust extraction port 330.

In the illustrated embodiment of FIG. 12, an oxidant-exhaust mixturepath 430 is coupled to the exhaust gas path 334 to route theoxidant-exhaust mixture 348 from the second flow path 328 to the firstflow path 326 downstream of the first distributor portion 394 of theflow distributor 332. As shown in FIG. 12, the compressed exhaust gas170 in the first flow path 326 may flow past, or bypass, the flowdistributor 332 to combine with the oxidant-exhaust mixture 348downstream of the flow distributor 332, thereby increasing theconcentration of the compressed exhaust gas 170 of the oxidant-exhaustmixture 348. In other embodiments, the oxidant-exhaust mixture path 430may not be coupled to the exhaust gas path 334. Instead, theoxidant-exhaust mixture path 430 may have an entrance separate from theentrance 362.

Next, the oxidant-exhaust mixture 348 may travel to the end plate 340before turning and entering the fuel nozzles 164. The fuel 70 may besupplied to the combustor 160 via the fuel supply system 342.Specifically, the axial fuel manifold 408 may supply the fuel 70 axially294 to one or more fuel intake ports 410 coupled to the end plate 340.As shown in FIG. 12, the oxidant-exhaust mixture 348 then enters thefuel nozzles 164 to be combined with the fuel 70 from the fuel supplysystem 342 before being combusted in the combustion portion 168 (e.g.,premix fuel nozzles). In other embodiments, the oxidant-exhaust mixture348 is not combined with the fuel 70 until exiting the fuel nozzles 164(e.g., diffusion fuel nozzles). In addition, the controller 118 may beused to control the exhaust extraction system 80 and the oxidantcompression system 186.

As illustrated in FIG. 12, the second exhaust extraction port 344 may becoupled to the flow distributor 332 of the second distributor portion396. As illustrated, the second exhaust extraction port 344 may be aradial port, thereby extracting the exhaust gas 170 radially 296 fromthe combustor 160. In certain embodiments, the flow distributor 332 ofthe second distributor portion 396 may include the exhaust gasextraction flow path 345 that routes the compressed exhaust gas 170 fromthe first flow path 326 through the flow distributor 332 to the exhaustextraction system 80. Thus, the flow distributor 332 of the seconddistributor portion 396 may include only one flow path, unlike the flowdistributor 332 of the first distributor portion 394 that includes morethan one flow path.

FIG. 13 is a radial cross-sectional view of the combustor 160 takenalong the line 13-13 of FIG. 12. As shown in FIG. 13, the path of thecompressed exhaust gas 170 in the second flow path 328 may be blocked bythe annular ring 360, which may be part of the flow distributor 332.Thus, for the first inserts 398 (e.g., the first distributor portion394), the compressed exhaust gas 170 in the second flow path 328 isforced into the exhaust gas path 334 and the oxidant-exhaust mixturepath 430. Specifically, the compressed exhaust gas 170 enters theentrance 362 of the exhaust gas path 334 and enters the head end chamber166 through the exit 364 to help cool the cap 331. In addition, thecompressed exhaust gas 170 enters an entrance 432 of the oxidant-exhaustmixture path 430 and enters the first flow path 326 through an exit 434to combine with the compressed exhaust gas 170 in the first flow path326. As described above, in certain embodiments, the oxidant-exhaustmixture path 430 may be coupled to the exhaust gas path 334. In suchembodiments, the entrance 432 may be omitted and the compressed exhaustgas 170 may enter the entrance 362 to enter both the exhaust gas path334 and the oxidant-exhaust mixture path 430. For the second inserts 400(e.g., the second distributor portion 396), the compressed exhaust gas170 in the first flow path 326 is forced into the exhaust gas extractionflow path 345. Specifically, the compressed exhaust gas 170 enters theentrance 368 of the exhaust gas extraction flow path 345 and exits theexit 370 to be extracted through the second exhaust extraction port 344.

As shown in FIG. 13, a plurality of first inserts 398 may be spacedapart from one another circumferentially 298 about the head end portion166 (e.g., fuel nozzles 164) and a plurality of second inserts 400 mayalso be spaced apart from one another circumferentially 298. Thus, thecompressed exhaust gas 170 in the first flow path 326 passes throughgaps 366 between the first and second inserts 398 and 400. In otherembodiments, the first and second inserts 398 and 400 may not be evenlyspaced apart from one another circumferentially 298. For example, theplurality of first and second inserts 398 and 400 may be disposed withinapproximately 60 degrees of top dead center of the combustor 160 becauseof packaging constraints associated with can-annular combustors. Inaddition, the first and second inserts 398 and 400 may not bedistributed circumferentially 298 in an alternating arrangement, asshown in FIG. 8. For example, if more extraction of the compressedexhaust gas 170 is desired, a pattern of two of the second inserts 400followed circumferentially 298 by one of the first inserts 398 may berepeated circumferentially 298. If additional extraction of thecompressed exhaust gas 170 is desired, a pattern of 3, 4, 5, 6 or moreof the second inserts 400 followed circumferentially 298 by one of thefirst inserts 398 may be repeated circumferentially 298. In otherembodiments, the arrangement of the first and second inserts 398 and 400may not follow a repeating pattern. For example, the first inserts 398may be disposed generally near top dead center of the combustor and thesecond inserts 400 may be disposed generally opposite from top deadcenter. Thus, the first and second inserts 398 and 400 may be arrangedcircumferentially 298 to achieve desired flow rates and/or placement ofextracted compressed exhaust gas 170 and compressed exhaust gas 170 usedfor cooling the cap 331.

FIG. 14 is a radial cross-sectional view of the combustor 160 takenalong the line 13-13 of FIG. 12. As shown in FIG. 14, the second annularring 380 may be disposed in the first flow path 326. The second annularring 380, which may be part of the flow distributor 332, may include aplurality of openings 382 for the compressed exhaust gas 170 to passthrough. Thus, the second annular ring 380 and the openings 382 may beused to adjust the flow rate of the compressed exhaust gas 170 throughthe first flow path 326. For example, providing more openings 382 mayenable additional compressed exhaust gas 170 to flow through the firstflow path 326. The openings 382 may be disposed circumferentially 298about the fuel nozzles 164. Although the openings 382 are shown ascircular openings in FIG. 14, the sizes, shapes, and/or locations of theopenings 382 may be adjusted to provide the desired flow rate of thecompressed exhaust gas 170 through the first flow path 326 and/or toaccommodate packaging limitations of individual combustors 160. Althoughthe entrances 362 and exits 364 are shown spaced apart from one anothercircumferentially 298 in FIG. 9, in other embodiments, the entrances 362and exits 364 may be disposed within approximately 60 degrees of topdead center of the combustor 160.

FIG. 15 is a cross-sectional view of an embodiment of the combustor 160.Elements in FIG. 15 in common with those shown in FIG. 12 are labeledwith the same reference numerals. The cross-sectional view shown in FIG.15 is similar to the view shown in FIG. 12, but focuses on the shape andarrangement of the components of the combustor 160 near the firstdistributor portion 394 of the flow distributor 332. For example, in theillustrated embodiment, the second flow path 328 includes a contouredsurface 390 near the flow distributor 332 to help guide theoxidant-exhaust mixture 348 into the entrance 362. In addition, thecontoured surface 390 may be used to adjust the flow rate of theoxidant-exhaust mixture 348 through the exhaust gas flow path 334 and/orthe oxidant-exhaust mixture path 430 in the flow distributor 332.Similarly, the first flow path 326 may include various contouredsurfaces to adjust the flow rate of the compressed exhaust gas 170through the first flow path 326. Further, the first and second walls 402and 404 may converge in the direction of the flow of the oxidant-exhaustmixture 348, which may help increase the velocity of the oxidant-exhaustmixture 348. As discussed below, numbers, placement, shapes, and/ordiameters of the exhaust gas path 334 and the oxidant-exhaust mixturepath 430 may be varied in a plurality of flow distributors 332 disposedcircumferentially 298 about the head end portion 166.

FIG. 16 is a cross-sectional view of an embodiment of the combustor 160.Elements in FIG. 16 in common with those shown in FIG. 12 are labeledwith the same reference numerals. The cross-sectional view shown in FIG.16 is similar to the view shown in FIG. 12, but focuses on the shape andarrangement of the components of the combustor 160 near the seconddistributor portion 396 of the flow distributor 332. For example, in theillustrated embodiment, the second flow path 328 includes the contouredsurface 390 near the flow distributor 332 to help guide theoxidant-exhaust mixture 348 toward the flow distributor 332. Similarly,the first flow path 326 may include various contoured surfaces to adjustthe flow rate of the oxidant-exhaust mixture 348 through the first flowpath 326. Further, the first and second walls 402 and 404 may convergein the direction of the flow of the oxidant-exhaust mixture 348, whichmay help increase the velocity of the oxidant-exhaust mixture 348. Asdiscussed below, numbers, placement, shapes, and/or diameters of theexhaust gas extraction flow path 345 may be varied in a plurality offlow distributors 332 disposed circumferentially 298 about the head endportion 166.

FIG. 17 is an exploded schematic of various configurations of the flowdistributors 334, which may be removably coupled to variouscircumferential 298 positions of the combustor 160. As illustrated, theflow distributors 334 include a plurality of swappable flow distributors450, 452, 454, 456, 458, 460, 462, 464, 466, 468, 470, and 472, whichdiffer in a variety of respects, such as having different passages,different passage geometries, and/or different numbers of passages.Thus, the flow distributors 450, 452, 454, 456, 458, 460, 462, 464, 466,468, 470, and 472 may selectively swapped out at each circumferential298 position of the flow distributor 332 to provide different flowarrangements for different operating conditions of the combustor 160.The flow distributors 450, 452, 454, 456, 458, 460, 462, 464, 466, 468,470, and 472 are shown as axial cross-sections. As shown below, thediameters, shapes, numbers, placement, and/or positions of the flowpaths of the flow distributors 332 may be varied to obtain differentflow distributors 332, which may then be placed circumferentially 298about the head end portion 166.

For example, flow distributors 450, 452, 454, 456, 466, 468, and 470 mayall include the exhaust gas flow path 334 that routes the compressedexhaust gas 170 to the cap 331. A diameter 476 of the exhaust gas flowpath 334 may be varied to adjust the flow rate of the compressed exhaustgas 170. For example, the diameter 476 of the exhaust gas flow path 334of flow distributors 450, 452, and 456 may be less than the diameter 476of flow distributor 454. By increasing the diameter 476, the flow rateof the compressed exhaust gas 170 to the cap 331 may be increased, whiledecreasing the diameter 476 may decrease the flow rate of the compressedexhaust gas 170. In certain embodiments, one or more of the flowdistributors may include a plurality of exhaust gas flow paths 334. Forexample, flow distributor 452 includes two exhaust gas flow paths 334,which may be used to provide the compressed exhaust gas 170 for coolingdifferent locations of the combustor 160.

Flow distributors 450, 452, 454, 456, 458, 460, 462, 464, 468, 470, and472 may all include the oxidant flow path 338 that routes the oxidant 68into the head end portion 166. A diameter 478 of the oxidant flow path338 may be varied to adjust the flow rate of the oxidant 68. Forexample, the diameter 478 of the oxidant flow path 338 of flowdistributors 450, 454, 458, 462, 468, 470, and 472 may be less than thediameter 478 of flow distributors 452 and 464. By increasing thediameter 478, the flow rate of the oxidant 68 may be increased, whiledecreasing the diameter 478 may decrease the flow rate of the oxidant68.

Flow distributors 456, 458, 460, 462, 464, 468, 470, and 472 may allinclude the exhaust gas extraction flow path 345 that routes the exhaustgas 42 to the exhaust extraction system 80. A diameter 480 of theexhaust gas extraction flow path 345 may be varied to adjust the flowrate of the exhaust gas 42. For example, the diameter 480 of the exhaustgas extraction flow path 345 of flow distributors 458, 464, 470, and 472may be less than the diameter 480 of flow distributors 460 and 462. Byincreasing the diameter 480, the flow rate of the exhaust gas 42 may beincreased, while decreasing the diameter 480 may decrease the flow rateof the exhaust gas 42. In certain embodiments, the flow distributors mayinclude a plurality of exhaust gas extraction flow paths 345. Forexample, flow distributor 472 includes two exhaust gas extraction flowpaths 345, which may be used to provide the exhaust gas 42 fromdifferent paths, such as the first and second flow paths 326 and 328. Inother embodiments, the exhaust gas extraction flow path 345 may couplewith other paths, such as the exhaust gas flow path 334 in flowdistributor 468.

In flow distributor 466, the exhaust gas flow path 334 is coupled to theoxidant-exhaust mixture path 430. Thus, the oxidant-exhaust mixture 348may be routed to both the cap 331 and to the fuel nozzles 164. As withthe previously-described flow distributors 334, diameters of the exhaustgas flow path 334 and the oxidant-exhaust mixture path 430 may be variedto achieve a desired split of the oxidant-exhaust mixture 348.

In flow distributor 468, an exhaust gas path 474 is coupled to both theexhaust gas flow path 334 and the exhaust gas extraction flow path 345.The exhaust gas path 474 may route the compressed exhaust gas 170through the flow distributor 468 to be combined with the oxidant 68flowing through the oxidant flow path 338. As with thepreviously-described flow distributors 334, diameters of the exhaust gaspath 474, exhaust gas flow path 334, and the exhaust gas extraction flowpath 345 may be varied to achieve a desired split of the compressedexhaust gas 170.

In one or more of the flow distributors 450, 452, 454, 456, 458, 460,462, 464, 466, 468, 470, and 472, relative diameters of different pathswithin a single flow distributor may be different from one another. Forexample, the diameter 476 of the exhaust gas flow path 334 may be largeror smaller than the diameter 478 of the oxidant flow path 338 or thediameter 480 of the exhaust gas extraction flow path 345. Similarly, thediameter 478 may be larger or smaller than diameters 476 or 480 and thediameter 480 may be larger or smaller than diameters 476 or 478. Therelationship between the diameters 476, 478, and 480 may also vary goingfrom one flow distributor to another circumferentially 298 about thehead end portion 166. As shown in FIG. 17, the diameter 478 of theoxidant flow path 338 in flow distributor 452 is larger than thediameter 476 of the exhaust gas flow path 334, whereas the diameter 478is smaller than the diameter 476 in flow distributor 454. Similarly, thediameter 478 of the oxidant flow path 338 is smaller than the diameter480 of the exhaust gas extraction flow path 345 in flow distributor 462,whereas the diameter 478 larger than the diameter 480 in flowdistributor 464.

FIG. 18 is a radial cross-sectional view of an embodiment of the turbinecombustor 160 with a plurality of flow distributors 334. Specifically,the combustor 160 includes flow distributors 334 disposed at first 490,second 492, third 494, fourth 496, fifth 498, sixth 500, seventh, 502,eighth 504, ninth 506, tenth 508, eleventh 510, twelfth 512, thirteenth514, fourteenth 516, fifteenth 518, and sixteenth 520 positionscircumferentially 298 disposed about the combustor 160. Each of the flowdistributors 334 disposed at the positions 490, 492, 494, 496, 498, 500,502, 504, 506, 508, 510, 512, 514, 516, 518, and 520 may be the same ordifferent from one another. For example, any of the flow distributors450, 452, 454, 456, 458, 460, 462, 464, 466, 468, 470, and 472 shown inFIG. 17 may be used in one or more of the positions 490, 492, 494, 496,498, 500, 502, 504, 506, 508, 510, 512, 514, 516, 518, and 520. Incertain embodiments, flow distributors 334 disposed at positions 490,492, 494, 496, 514, 516, 518, and 520 may different from flowdistributors 334 disposed at positions 498, 500, 502, 504, 506, 508,510, and 512. In other embodiments, two types of flow distributors 334may be disposed in an alternating arrangement. For example, flowdistributors 334 disposed at positions 490, 494, 498, 502, 506, 510,514, and 518 may be different from flow distributors 334 disposed atpositions 492, 496, 500, 504, 508, 512, 516, and 520. In furtherembodiments, 2, 3, 4, or more different types of flow distributors 334may be disposed in various patterns. Thus, the plurality of flowdistributors 334 may be selected and disposed at the various positions490, 492, 494, 496, 498, 500, 502, 504, 506, 508, 510, 512, 514, 516,518, and 520 depending on the specific uses of the combustor 160. Infurther embodiments, the sizes of passages within the flow distributors334 may be varied circumferentially 298 about the head end portion 166.For example, it may be desirable to have more or less oxidant injectionor exhaust flow at different circumferential 298 positions. Where moreflow is desired, the sizes of the passages may be larger than where lessflow is desired.

FIG. 19 is a radial cross-sectional view of an embodiment of the turbinecombustor with a plurality of passages 530, which may be any of theexhaust gas flow path 334, oxidant flow path 338, exhaust gas extractionflow path 345, oxidant-exhaust mixture path 430, and/or exhaust gas path474 described above. The illustrated passages 530 may be disposed in oneor more flow distributors 334, such as those described in detail above.As shown in FIG. 19, the passages 530 may not be disposed uniformlycircumferentially 298 about the combustor 160. For example, the passages530 disposed in a first region 532 may be spaced further apart from oneanother than the passages disposed in a second region 534. Passages 530disposed in a third region 536 may be disposed apart from one another anintermediate distance compared to the passages 530 of the first andsecond regions 532 and 534. Such an arrangement of passages 530 may beused to provide a desired flow of gas in a particular location of thecombustor 160. For example, if the passages 530 are exhaust gas flowpaths 334, additional cooling of the cap 331 may be provided in thesecond region 534 compared to the first region 532. In certainembodiments, the second region 534 may be closest to the compressordischarge where the pressure of the exhaust may be higher. Thus, ahigher concentration of passages 530 may be desirable in the secondregion 534. In further embodiments, fewer or more regions of passages530 may be disposed circumferentially 298 about the combustor 160.

FIG. 20 is a radial cross-sectional view of an embodiment of the turbinecombustor 160 with a plurality of passages 530 of different diameters.For example, diameters 550 of the passages 530 of the first region 532may be less than diameters 552 of the passages 530 of the second region534. Passages 530 disposed in the third region 536 may have diameters554 intermediate in dimension compared to the diameters 550 and 552 ofthe first and second regions 532 and 534, respectively. Varying thediameters 550, 552, and 554 may be used to achieve desired flow rates ofthe gases flowing through the passages 530. For example, the passages530 of the second region 534 may provide higher flow rates compared tothe passages 530 of the first region 532, which may be desirable inembodiments in which the second region 534 is closer to the compressordischarge. In other embodiments, the diameters 550, 552, and 554 of thepassages 530 may be varied differently than that shown in FIG. 20. Forexample, diameters 550 of the first region 532 may be greater thandiameters 552 of the second region 534. In other embodiments, thediameters 550, 552, and 554 may follow regular or non-regular patternscircumferentially 298 about the combustor 160.

As described above, certain embodiments of the combustor 160 may includethe head end portion 166, the combustion portion 168 disposed downstreamfrom the head end portion 166, and the cap 331 disposed between the headend portion 166 and the combustion portion 68. In addition, thecombustor 160 may include the flow distributor 332 to distribute theexhaust gas 42 or the compressed exhaust gas 170 circumferentially 298around the head end chamber 166. Specifically, the flow distributor 332directs the compressed exhaust gas 170 into the head end portion 166.The flow distributor 332 may also direct the compressed exhaust gas 170to the exhaust extraction system 80 and the flow distributor 332 mayreceive the oxidant 68 from the oxidant compressor system 186. Thecombustor 160 may also include the mixing region 346, which may beupstream or downstream of the flow distributor 332, to mix thecompressed exhaust gas 170 with the oxidant 68 to provide theoxidant-exhaust mixture 348. In the disclosed embodiments, thecompressed exhaust gas 170 and/or the oxidant-exhaust mixture 348 may bedirected by the flow distributor 332 to cool the combustion liner 324 orcap 331, thereby extending the life span of the combustion liner 324 orcap 331. In addition, the circumferential arrangement of the flowdistributor 332 may be used to direct flows of gases where desired. Forexample, the flow distributor 332 may be used to direct the compressedexhaust gas 170 and/or the oxidant-exhaust mixture 348 to portions ofthe cap 331 for additional cooling. Diameters of passages 530 may beincreased and/or additional flow distributors 332 (e.g., first or secondinserts 398 or 400) disposed where higher flow rates are desired.

Additional Description

The present embodiments provide systems and methods for turbinecombustors of gas turbine engines. It should be noted that any one or acombination of the features described above may be utilized in anysuitable combination. Indeed, all permutations of such combinations arepresently contemplated. By way of example, the following clauses areoffered as further description of the present disclosure:

Embodiment 1

A system, comprising: a turbine combustor, comprising: a head endportion having a head end chamber; a combustion portion having acombustion chamber disposed downstream from the head end chamber; a capdisposed between the head end chamber and the combustion chamber; and aflow distributor configured to distribute an exhaust flowcircumferentially around the head end chamber, wherein the flowdistributor comprises at least one exhaust gas flow path.

Embodiment 2

The system of embodiment 1, wherein the flow distributor comprises: afirst flow distributor portion configured to distribute the exhaust flowalong a first portion of the head end chamber; and a second flowdistributor portion configured to distribute the exhaust flow along asecond portion of the head end chamber.

Embodiment 3

The system defined in any preceding embodiment, wherein the first andsecond flow distributor portions are different from one another.

Embodiment 4

The system defined in any preceding embodiment, wherein the first flowdistributor portion is configured to distribute the exhaust flow at afirst flow rate, wherein the second flow distributor portion isconfigured to distribute the exhaust flow at a second flow rate.

Embodiment 5

The system defined in any preceding embodiment, wherein the first andsecond flow rates are different from one another.

Embodiment 6

The system defined in any preceding embodiment, wherein the first flowdistributor portion comprises a first arcuate portion of the head endchamber, and the second flow distributor portion comprises a secondarcuate portion of the head end chamber.

Embodiment 7

The system defined in any preceding embodiment, wherein the first andsecond flow distributor portions are circumferentially offset from oneanother.

Embodiment 8

The system defined in any preceding embodiment, wherein the first flowdistributor portion comprises a first radial insert and the second flowdistributor portion comprises a second radial insert.

Embodiment 9

The system defined in any preceding embodiment, wherein the first flowdistributor portion comprises a plurality of first radial inserts, andthe second flow distributor portion comprises a plurality of secondradial inserts.

Embodiment 10

The system defined in any preceding embodiment, wherein the plurality offirst radial inserts is uniformly disposed circumferentially around thehead end chamber, and the plurality of second radial inserts isuniformly disposed circumferentially around the head end chamber.

Embodiment 11

The system defined in any preceding embodiment, wherein each of theplurality of first radial inserts is spaced apart from one another by afirst distance, and each of the plurality of second radial inserts isspaced apart from one another by a second distance.

Embodiment 12

The system defined in any preceding embodiment, wherein the firstdistance is less than the second distance, and the plurality of firstradial inserts is disposed near a compressor discharge of the turbinecombustor.

Embodiment 13

The system defined in any preceding embodiment, wherein each of theplurality of first radial inserts comprises at least one first passagecomprising a first exhaust gas flow path, a first oxidant flow path, afirst exhaust gas extraction flow path, a first cooling gas flow path, afirst oxidant-exhaust mixture path, or any combination thereof, whereineach of the plurality of second radial inserts comprises at least onesecond passage comprising a second exhaust gas flow path, a secondoxidant flow path, a second exhaust gas extraction flow path, a secondcooling gas flow path, a second oxidant-exhaust mixture path, or anycombination thereof.

Embodiment 14

The system defined in any preceding embodiment, wherein a first diameterof the at least one first passage is different from a second diameter ofthe at least one second passage.

Embodiment 15

The system defined in any preceding embodiment, wherein the firstdiameter is greater than the second diameter, and the first radialinserts are disposed near a compressor discharge of the turbinecombustor.

Embodiment 16

The system defined in any preceding embodiment, wherein the plurality offirst radial inserts and the plurality of second radial inserts aredisposed circumferentially around the head end chamber in a repeatingpattern.

Embodiment 17

The system defined in any preceding embodiment, wherein the repeatingpattern comprises at least one of two first radial inserts followedcircumferentially by one second radial insert, three first radialinserts followed circumferentially by one second radial insert, fourfirst radial inserts followed circumferentially by one second radialinsert, or any combination thereof.

Embodiment 18

The system defined in any preceding embodiment, wherein the first flowdistributor portion comprises the exhaust gas flow path configured toconvey the exhaust flow radially to a cooling region adjacent the capand a first oxidant flow path configured to convey an oxidant flowradially from an oxidant compressor system, and wherein the second flowdistributor portion comprises an exhaust gas extraction flow pathconfigured to convey the exhaust flow radially to an exhaust extractionsystem and a second oxidant flow path configured to convey the oxidantflow radially from the oxidant compressor system.

Embodiment 19

The system defined in any preceding embodiment, wherein the first flowdistributor portion comprises a cooling gas flow path configured toconvey an oxidant-exhaust mixture radially to a cooling region adjacentthe cap and an oxidant-exhaust mixture path configured to convey theoxidant-exhaust mixture axially from a mixing region upstream of theflow distributor, and wherein the second flow distributor portioncomprises an exhaust gas extraction flow path configured to convey theexhaust flow radially to an exhaust extraction system.

Embodiment 20

The system defined in any preceding embodiment, wherein the turbinecombustor comprises an exhaust extraction port configured to extract theexhaust flow from the turbine combustor.

Embodiment 21

The system defined in any preceding embodiment, wherein the exhaustextraction port is coupled to a casing disposed about the turbinecombustor upstream of the flow distributor, coupled to the flowdistributor, or any combination thereof

Embodiment 22

The system defined in any preceding embodiment, wherein the turbinecombustor comprises an oxidant intake port configured to supply anoxidant flow to the turbine combustor.

Embodiment 23

The system defined in any preceding embodiment, wherein the oxidantintake port is coupled to a casing disposed about the turbine combustorupstream of the flow distributor, coupled to the flow distributor, orany combination thereof.

Embodiment 24

The system defined in any preceding embodiment, comprising a mixingregion configured to mix the exhaust flow with an oxidant flow toprovide an oxidant-exhaust mixture.

Embodiment 25

The system defined in any preceding embodiment, wherein the mixingregion is disposed either upstream or downstream of the flowdistributor.

Embodiment 26

The system defined in any preceding embodiment, wherein the flowdistributor comprises a plurality of flow distributor portions, and eachof the plurality of flow distributor portions comprises the at least oneexhaust gas flow path.

Embodiment 27

The system defined in any preceding embodiment, wherein spacings betweeneach of the plurality of flow distributor portions are different fromone another.

Embodiment 28

The system defined in any preceding embodiment, wherein diameters of theexhaust gas flow paths of the plurality of flow distributor portions aredifferent from one another.

Embodiment 29

The system defined in any preceding embodiment, comprising a gas turbineengine having the turbine combustor, a turbine driven by combustionproducts from the turbine combustor, and an exhaust gas compressordriven by the turbine, wherein the exhaust gas compressor is configuredto compress and route an exhaust gas to the turbine combustor.

Embodiment 30

The system defined in any preceding embodiment, comprising an exhaustgas extraction system coupled to the gas turbine engine, and ahydrocarbon production system coupled to the exhaust gas extractionsystem.

Embodiment 31

The system defined in any preceding embodiment, wherein the gas turbineengine is a stoichiometric exhaust gas recirculation (SEGR) gas turbineengine.

Embodiment 32

A system, comprising: an oxidant compressor; and a gas turbine engine,comprising: a combustor section having a turbine combustor; a turbinedriven by combustion products from the turbine combustor; an exhaust gascompressor driven by the turbine, wherein the exhaust gas compressor isconfigured to compress and route an exhaust flow to the turbinecombustor, and the oxidant compressor is configured to compress androute an oxidant flow to the turbine combustor; an exhaust extractionport coupled to the combustor section; and a flow distributor configuredto distribute an exhaust flow circumferentially around a head endchamber of the turbine combustor, wherein the flow distributor comprisesat least one exhaust gas flow path.

Embodiment 33

The system defined in any preceding embodiment, wherein the exhaustextraction port is coupled to a casing disposed about the turbinecombustor upstream of the flow distributor, coupled to the flowdistributor, or any combination thereof.

Embodiment 34

The system defined in any preceding embodiment, wherein the turbinecombustor comprises an oxidant intake port configured to supply theoxidant flow to the turbine combustor.

Embodiment 35

The system defined in any preceding embodiment, wherein the oxidantintake port is coupled to a casing disposed about the turbine combustorupstream of the flow distributor, coupled to the flow distributor, orany combination thereof

Embodiment 36

The system defined in any preceding embodiment, comprising a mixingregion configured to mix the exhaust flow with the oxidant flow toprovide the oxidant-exhaust mixture.

Embodiment 37

The system defined in any preceding embodiment, wherein the mixingregion is disposed either upstream or downstream of the flowdistributor.

Embodiment 38

The system defined in any preceding embodiment, comprising: wherein theflow distributor comprises a plurality of radial inserts each comprisingat least one passage, and at least one insert comprises the exhaust gasflow path.

Embodiment 39

The system defined in any preceding embodiment, wherein the at least onepassage comprises the exhaust gas flow path, an oxidant flow path, anexhaust gas extraction flow path, a cooling gas flow path, anoxidant-exhaust mixture path, or any combination thereof.

Embodiment 40

The system defined in any preceding embodiment, wherein diameters of thepassages of the plurality of radial inserts are different from oneanother.

Embodiment 41

The system defined in any preceding embodiment, wherein spacings betweeneach of the plurality of radial inserts are different from one another.

Embodiment 42

The system defined in any preceding embodiment, wherein the flowdistributor comprises a plurality of flow distributor portions, and eachof the plurality of flow distributor portions comprises the at least oneexhaust gas flow path.

Embodiment 43

The system defined in any preceding embodiment, wherein spacings betweeneach of the plurality of flow distributor portions are different fromone another.

Embodiment 44

The system defined in any preceding embodiment, wherein diameters of theexhaust gas flow paths of the plurality of flow distributor portions aredifferent from one another.

Embodiment 45

The system defined in any preceding embodiment, comprising astoichiometric exhaust gas recirculation (SEGR) turbine system havingthe oxidant compressor and the gas turbine engine.

Embodiment 46

The system defined in any preceding embodiment, comprising an exhaustgas extraction system coupled to the exhaust extraction port of the SEGRturbine system, and a hydrocarbon production system coupled to theexhaust gas extraction system.

Embodiment 47

A method, comprising: extracting a first exhaust flow of an exhaust gasat a combustion section of a gas turbine engine; routing a secondexhaust flow of the exhaust gas toward an end plate of a head endportion of a turbine combustor in the combustion section; routing athird exhaust flow of the exhaust gas toward a cap of the head endportion, wherein the cap is disposed between a head end region and acombustion region; routing an oxidant flow into the head end portion;and distributing at least one of the first exhaust flow, the secondexhaust flow, or the third exhaust flow circumferentially around thehead end portion using a flow distributor, wherein the flow distributorcomprises at least one exhaust gas flow path.

Embodiment 48

The method or system defined in any preceding embodiment, whereinextracting the first exhaust flow comprises extracting the first exhaustflow through an exhaust extraction port coupled to a casing disposedabout the turbine combustor or the flow distributor.

Embodiment 49

The method or system defined in any preceding embodiment, whereinrouting the oxidant flow comprises supplying the oxidant flow through anoxidant intake port coupled to a casing disposed about the turbinecombustor or the flow distributor.

Embodiment 50

The method or system defined in any preceding embodiment, whereinrouting the third exhaust flow comprises routing the third exhaust flowthrough the exhaust gas flow path.

Embodiment 51

The method or system defined in any preceding embodiment, comprisingdifferentially distributing the at least one of the first exhaust flow,the second exhaust flow, or the third exhaust flow circumferentiallyaround the head end portion using the flow distributor.

Embodiment 52

The method or system defined in any preceding embodiment, comprisingstoichiometrically combusting a mixture of a fuel flow, the oxidantflow, and the second and third exhaust flows.

Embodiment 53

The method or system defined in any preceding embodiment, comprisingrouting the first exhaust flow to a hydrocarbon production system.

Embodiment 54

The method or system defined in any preceding embodiment, wherein theturbine combustor is configured to combust a mixture of a fuel and anoxidant with an equivalence ratio of approximately 0.95 to approximately1.05.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal language of the claims.

1. A system, comprising: a turbine combustor, comprising: a head endportion having a head end chamber; a combustion portion having acombustion chamber disposed downstream from the head end chamber; a capdisposed between the head end chamber and the combustion chamber; and aflow distributor configured to distribute an exhaust flowcircumferentially around the head end chamber, wherein the flowdistributor comprises at least one exhaust gas flow path.
 2. The systemof claim 1, wherein the flow distributor comprises: a first flowdistributor portion configured to distribute the exhaust flow along afirst portion of the head end chamber; and a second flow distributorportion configured to distribute the exhaust flow along a second portionof the head end chamber.
 3. The system of claim 2, wherein the first andsecond flow distributor portions are different from one another.
 4. Thesystem of claim 2, wherein the first flow distributor portion isconfigured to distribute the exhaust flow at a first flow rate, whereinthe second flow distributor portion is configured to distribute theexhaust flow at a second flow rate.
 5. (canceled)
 6. The system of claim2, wherein the first flow distributor portion comprises a first arcuateportion of the head end chamber, and the second flow distributor portioncomprises a second arcuate portion of the head end chamber.
 7. Thesystem of claim 2, wherein the first and second flow distributorportions are circumferentially offset from one another.
 8. (canceled) 9.The system of claim 2, wherein the first flow distributor portioncomprises a plurality of first radial inserts, and the second flowdistributor portion comprises a plurality of second radial inserts. 10.The system of claim 9, wherein the plurality of first radial inserts isuniformly disposed circumferentially around the head end chamber, andthe plurality of second radial inserts is uniformly disposedcircumferentially around the head end chamber.
 11. (canceled) 12.(canceled)
 13. The system of claim 9, wherein each of the plurality offirst radial inserts comprises at least one first passage comprising afirst exhaust gas flow path, a first oxidant flow path, a first exhaustgas extraction flow path, a first cooling gas flow path, a firstoxidant-exhaust mixture path, or any combination thereof, wherein eachof the plurality of second radial inserts comprises at least one secondpassage comprising a second exhaust gas flow path, a second oxidant flowpath, a second exhaust gas extraction flow path, a second cooling gasflow path, a second oxidant-exhaust mixture path, or any combinationthereof. 14.-17. (canceled)
 18. The system of claim 2, wherein the firstflow distributor portion comprises the exhaust gas flow path configuredto convey the exhaust flow radially to a cooling region adjacent the capand a first oxidant flow path configured to convey an oxidant flowradially from an oxidant compressor system, and wherein the second flowdistributor portion comprises an exhaust gas extraction flow pathconfigured to convey the exhaust flow radially to an exhaust extractionsystem and a second oxidant flow path configured to convey the oxidantflow radially from the oxidant compressor system.
 19. (canceled)
 20. Thesystem of claim 1, wherein the turbine combustor comprises an exhaustextraction port configured to extract the exhaust flow from the turbinecombustor.
 21. (canceled)
 22. The system of claim 1, wherein the turbinecombustor comprises an oxidant intake port configured to supply anoxidant flow to the turbine combustor.
 23. (canceled)
 24. The system ofclaim 1, comprising a mixing region configured to mix the exhaust flowwith an oxidant flow to provide an oxidant-exhaust mixture. 25.-28.(canceled)
 29. The system of claim 1, comprising a gas turbine enginehaving the turbine combustor, a turbine driven by combustion productsfrom the turbine combustor, and an exhaust gas compressor driven by theturbine, wherein the exhaust gas compressor is configured to compressand route an exhaust gas to the turbine combustor.
 30. The system ofclaim 29, comprising an exhaust gas extraction system coupled to the gasturbine engine, and a hydrocarbon production system coupled to theexhaust gas extraction system.
 31. The system of claim 29, wherein thegas turbine engine is a stoichiometric exhaust gas recirculation (SEGR)gas turbine engine.
 32. A system, comprising: an oxidant compressor; anda gas turbine engine, comprising: a combustor section having a turbinecombustor; a turbine driven by combustion products from the turbinecombustor; an exhaust gas compressor driven by the turbine, wherein theexhaust gas compressor is configured to compress and route an exhaustflow to the turbine combustor, and the oxidant compressor is configuredto compress and route an oxidant flow to the turbine combustor; anexhaust extraction port coupled to the combustor section; and a flowdistributor configured to distribute an exhaust flow circumferentiallyaround a head end chamber of the turbine combustor, wherein the flowdistributor comprises at least one exhaust gas flow path. 33.-37.(canceled)
 38. The system of claim 32, wherein the flow distributorcomprises a plurality of radial inserts each comprising at least onepassage, and at least one insert comprises the exhaust gas flow path.39.-46. (canceled)
 47. A method, comprising: extracting a first exhaustflow of an exhaust gas at a combustion section of a gas turbine engine;routing a second exhaust flow of the exhaust gas toward an end plate ofa head end portion of a turbine combustor in the combustion section;routing a third exhaust flow of the exhaust gas toward a cap of the headend portion, wherein the cap is disposed between a head end region and acombustion region; routing an oxidant flow into the head end portion;and distributing at least one of the first exhaust flow, the secondexhaust flow, or the third exhaust flow circumferentially around thehead end portion using a flow distributor, wherein the flow distributorcomprises at least one exhaust gas flow path. 48.-50. (canceled)
 51. Themethod of claim 47, comprising differentially distributing the at leastone of the first exhaust flow, the second exhaust flow, or the thirdexhaust flow circumferentially around the head end portion using theflow distributor.
 52. (canceled)
 53. (canceled)